Power Sector Reforms - Orissa Perspective

Power Sector Reforms in India: A Critical Appraisal of Orissa’s Reforms

Experience

A Thesis Submitted to the Utkal University in Partial Fulfilment of the Requirement for the Degree of

DOCTOR OF PHILOSOPHY

IN COMMERCE

By MR. SARBESH MISHRA

Under The Supervision of

PROF. AMBIKA PRASAD DASH

DR. MALAY KUMAR MOHANTY

UTKAL UNIVERSITY

Bhubaneswar 2008

2

Department of Commerce

Utkal University,

Bhubaneswar.

DECLARATION

I hereby declare that this thesis entitled “Power Sector Reforms in India: A

Critical Appraisal of Orissa’s Reforms Experience” submitted to the Utkal

University in fulfillment of the requirements for the award of the Degree of

Doctor of Philosophy in Commerce is a bonafide record of original research

work done by me under the supervision and guidance of Professor Ambika

Prasad Dash and Dr. Malay Kumar Mohanty and the thesis has not been

submitted to any other University or Institution for the award of any degree or

diploma.

(Signature of the Candidate)

SARBESH MISHRA

Enrolment No: 6-commerce-2003-2004

Date of Registration: 27.5.2004.

3

Prof. Ambika Prasad Dash Dr. Malay Kumar Mohanty

Power Management Institute Ravenshaw University

NOIDA – 201306 (U.P) Department of Commerce

Cuttack – 753003, Orissa.

CERTIFICATE

This is to certify that the thesis titled “Power Sector Reforms in India: A critical

Appraisal of Orissa’s Reforms Experience” submitted to the Utkal University,

Bhubaneswar in fulfillment of the requirements for the award of the Degree of

Doctor of Philosophy in Commerce is a bonafide record of original research work

done by Mr. Sarbesh Mishra, under our supervision and guidance and this thesis has

not been submitted to any other University or Institution for the award of any

degree.

(Ambika Prasad Dash) (Malay Kumar Mohanty)

4

Prof. Ambika Prasad Dash Dr. Malay Kumar Mohanty

Power Management Institute Ravenshaw University

NOIDA – 201306 (U.P) Department of Commerce

Cuttack – 753003, Orissa.

AREA CERTIFICATE

The work done by the candidate is original and within the area of registration for

which the candidate has already been for the registration.

(Ambika Prasad Dash) (Malay Kumar Mohanty)

5

ACKNOWLEDGEMENT

I express my profound gratitude to my supervisors, Professor A.P Dash and

Dr. M K Mohanty, whose benign guidance has enlightened my path through the

course of this work. Besides their dedication to academic life, their disciplined and

austere habits have been a source of constant inspiration to me. They are humane

with willingness to help others, care for everyone, and always being concerned

about the progress. With these rare qualities I have found in them not merely

supervisor but a noble soul, a “Guru”.

I express my gratitude to Prof. Arabinda Mishra, TERI University, New

Delhi, Prof. Tanmay Panda, BITS, PILANI (DUBAI) Campus for their continuous

concern about my progress in research. My special thanks to Mr. Sovan Kanungo,

IAS, Prof. Rajat Bakshi, MDI, Gurgaon, Mr. P Chanda, AGM, NTPC Ltd. Dr. G N

Patel, Registrar, BIMTECH, Prof. Mukesh Chaturvedi, MDI, Gurgaon, Maj. Gen. N.

K Dhir, Prof. P K Mishra, HoD, Environmental Science, Jyotivihar, Mr. Dillip Raj

Behera, DGM, Public Relations, OPTCL and Mr. S.N Sabat, IPS, DIG of Police,

Uttar Pradesh for their guidance during different stages of this research.

I am thankful to other teachers of the department Prof. S Moharana, HoD,

Department of Commerce, Prof. Ranjan Kumar Bal, Dr. J K Parida, Dr. P K Hota,

Dr. K B Das, Dr. M Sahu, Mr. A K Sahu for their encouragement and interest in my

academic pursuit.

I acknowledge my sincere gratitude to University of Delhi for allowing me to

pursue PhD work being a faculty member. I also acknowledge the help and facilities

availed from Army Institute of Management & Technology, Greater NOIDA and I

extend my profound regards to late Director of the institute Prof. (Brigadier) M. M.

Trivedi, VSM for his timely help and encouragement.

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I cannot express my gratitude in words to my late father Shri Indramadhab

Mishra, whose blessings have always been with me throughout this work along with

the best wishes from my family members, mother Ms. Puspalata Mishra, my elder

brother Mr. Abesh Mishra, my brother-in-law Mr. B P Dwivedi, my sister Ms.

Ajanta Dwivedi and my sister-in-law Ms. Saswati Mishra . It’s needless to mention

about my wife Sushree’s contribution, in each and every step of this research work

she has willingly extended her cooperation

My special thanks must go to my guide’s family for their timely help and

constant inspiration. My sincere regards and thanks to Prof. Suman Mahapatra,

Dean, School of Languages, Ravenshaw University for his painstaking effort of

correcting my thesis meticulously and also to Mr. K. Anand, Acquisition Editor,

Vikas Publishing House for undertaking to publish my thesis after its

acknowledgement.

It is my pleasure to acknowledge Mr. Vineet Sahu, Mr. Satya Sundar Panda,

Mr. Saurav Rath and Mr. Amarendra Mohanty for their moral support and timely

inspiration.

(Sarbesh Mishra)

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LIST OF TABLE

Page No. 1. Table 1: Power Sector Performance: Gaps between Targets and Realities on Key Indicators in a sampling 17

of regions and Countries. 2. Table 2: Generation of Power – Sector wise 22

and Compositions 3. Table 3: Hydel Potential – Global Scenario 23 4. Table 4: States with substantial undeveloped 23

Hydro potential 5. Table 5: Inter-regional Links under Operation 24 6. Table 6: Plan Outlay On power Sector (1961-90) 27 7. Table 7: Installed Power Capacity 1950 to 2000 27 8. Table 8: Installed Capacity (MW) At a Glance 27 9. Table 9: Physical Performance (At the All India Level) 28 10. Table 10: Public Sector Investment In power 1992-2002 32 11. Table 11: Capacity Addition 1992-2002 32 12. Table 12: Tenth Plan Power Sector Outlay (2002-07) 36 13. Table 13: Financing Pattern of Central Sector outlay in 36

Tenth Plan (Rs. Crore at 2001-02 prices) 14. Table 14: Electricity Consumption in Brazil 55

Twh (1994 – 2002) 15. Table 15: Comparative statement of sops extended by 108

different countries 16. Table 16: Estimated Break-up of T& D losses in M.P 149 17. Table 17: Achievement of OSEB during 35 years 163 18. Table 18: Accounting P\L 173

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19. Table 19: Cash P\L 173 20. Table 20: Details of Revaluation 178 21. Table 21: Debt Equity Comparison 180 22. Table 22: Profit / (Loss) Comparison Over The Years 181 23. Table 23: Details Of Loans 182 24. Table 24: Statement Of Power Purchase, Sale, T& D Loss 183

Billing Collection, etc 25. Table 25: Sources & Application of Funds 184 26. Table 26: Expenditure Incurred On Consultancy Services 185 27. Table 27: Revaluation of Assets 204 28. Table 28: Financial Result Analysis of Andhra Pradesh 211 29. Table 29: Financial Result Analysis of Orissa 211 30. Table 5.1: Indicators of Access to Electricity by 219

Sample Households 31. Table 5.2: Metering of Households in Rural and 222

Urban areas 32. Table 5.3: Uses of Electricity by Households in Rural 223

and Urban Areas 33. Table 5.4: Economy in use of electricity by members of 224

the household 34. Table 5.5: Reasons for Economy in Use by Households 225

in reform period 35. Table 5.6: Perceived changes in electricity tariff in reform 226

period 36. Table 5.7: Billing frequency as reported by the households 228 37. Table 5.8: Irregularity in Billing 228 38. Table 5.9: Billing efficiency in rural and urban areas 230

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39. Table 5.10: Consumer perceptions on power supply 231

in the reform period 40. Table 5.11: Duration of Power Failure in pre-reform 232

and reform periods 41. Table 5.12: Duration of power cut during pre reform 234

And reform periods 42. Table 5.13: Alternative sources of lighting used by 235

consumers during power cut/failure 43. Table 5.14: Consumer perceptions on voltage 236

quality in reform period 44. Table 5.15: Difficulties reported due to voltage 237

problem in the reform period 45. Table 5.16: Protective measures by households in 237

case of voltage problem 46. Table-5.17: Consumer perceptions about reform’s 240

impact on education of children 47. Table-5.18: Consumer perceptions about reform’s 242

impact on health services and health care in households 48. Table-5.19: Consumer perceptions about reform’s 243

impact on women 49. Table 5.20: Employment in cottage, tiny and small 244

scale industries 50. Table 5.21 Summary statement of the perceptions 246

of HHs on impact indicators 51. Table 5.22: Consumer’s Willingness to Pay for 247

Electricity at a Hiked Rate of Tariff by Levels of Education

52. Table 5.23: District wise status of Metering 248 of sample units belonging to commercial and industrial category

53. Table 5.24: District wise status of Supply of 249 Electricity to commercial and industrial users

54. Table 5.24: Alternative Sources of Power / Stand 250

by Facilities and the associated cost for commercial and industrial users of different capacity size (KW terms)

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List of Charts Page No.

1. Chart 1: Power generation mix during several 21 plan period

2. Chart 2: Reasons for poor financial health 25

3. Chart 3: Plant load factor (PLF) 41

4. Chart 4: Load duration curve 41

5. Chart 5: T&D loss determination between four states 140

6. Chart 6: Relationship between different party 161

7. Chart 7: GRIDCO structure 169

8. Chart 8: Reasons for economy in use of electricity 218

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CONTENTS

Page No.

Declaration ii

Certificate iii

Area Certificate iv

Acknowledgements v

List of Table vii

List of Charts x

CHAPTERS

1. INTRODUCTION

I. Backdrop of Power Sector Reforms 1

II. Review of Literature 2

III. Significance of Study 10

IV. Objective of the Study 11

V. Hypotheses of the Study 12

VI. Scope and Limitations of the Study 12

VII. Methodology of the Study 13

VIII. Organisation of the Study 14

2. POWER SECTOR REFORMS: A CONCEPTUAL

FRAMEWORK

i. Introduction 15

ii. What is Reforms 17

iii. Role of Power Sector in Indian Perspective 19

iv. Power Sector in Pre-reform Period (1961 – 90) 26

v. Indian Economy: Growth of Power Sector 26

vi. Power Sector during Reforms period (1992 – 2002) 29

vii. Original Electricity Bill 2001 35

viii. Private Sector Participation in Generation 37

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III. GROWTH OF POWER SECTOR

i. International Scenario of Power Sector 39

United Kingdom (UK) 39

United State of America (USA) 44

Brazil 52

Argentina 56

iii. Indian State’s Experiences 60

Andhra Pradesh Reforms 62

Delhi Reforms 79

IV. POWER SECTOR REFORMS

i. Electricity Act. 2003 97

ii. Single Buyer Vs. Multi buyer Model in Distribution 105

iii. World Bank Models on Unbundling of PSUs 109

iv. Reforms in Electricity Tariffs 110

v. Availability Based Tariff 122

vi. Methods of Calculation of Cross Subsidy 132

vii. High Transmission Energy Audit 138

V. RESTRUCTURING INITIATIVES IN ORISSA’S POWER SECTOR

i. Introduction 158

ii. First Phase of Reforms 159

iii. Second Phase of Reforms 164

iv. Restructuring of GRIDCO 166

v. Sequence of events of reforms 170

vi. Benefits of Reforms 172

vii. Analysis of Fault lines – 186

Kanungo Committee’s Findings

viii. Turnaround of GRIDCO – A Case Study 202

ix. Comparison of Financial Performance: 211

Orissa Vis-à-vis Andhra Pradesh

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VI. SOCIO ECONOMIC IMPACT ASSESSMENT OF POWER

SECTOR REFORMS

i. Introduction 213

ii. Micro level data source: Sampling framework 214

iii. Analysis of household data 216

iv. Uses of Electricity 223

v. Electricity Tariff 226

vi. Problems in supply of Power 230

vii. Socio economic impact of reform on education 238

viii. Socio-economic impact of reforms on Health 241

ix. Socio economic impact of reforms on women 242

x. Impact of power sector reform on livelihood 244

xi. Consumer’s willingness to pay at hiked rate 247

VII. CONCLUSION

• Summary 252

• Findings 256

• Suggestions 266

• Scope for further research 268

VIII. SCHEDULE OF ENACTMENTS 269

IX. LIST OF ABBREVIATIONS 270

X. BIBLIOGRAPHY AND REFERENCES 273

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Backdrop of Power Sector Reforms

The Indian constitution has included power in concurrent list, which means

both the centre and state share the responsibility for this sector. Article 246 of

the constitution vests the parliament as well as the state legislature with the

power to frame laws. The Electricity Supplies Act. 1948 was amended in

1991 to permit private sector participation in generation. Many Independent

Power Producers (IPPs) came with their proposals but very few could get the

financial closure and commissioning of power plants in 10 years. The most

important factor was that most of the state electricity boards were fast moving

towards bankruptcy. The reforms carried out in 1991 in the area of power

generation made us realize that reform has to begin from distribution end for

sustainable development of power. The process of distribution reform started

with the enactment of regulatory Act. In 1998 to minimize the political

interference in power sector and rationalize the tariff. In pursuance to reforms,

states started unbundling the vertically integrated structure of state electricity

boards (SEBs) into three separate corporate identities of Generation,

Transmission and Distribution as a precursor to the participation of private

sector in distribution.

Learning from the Orissa experience, the main metric for choosing companies

was not based on valuation, but on performance improvement goals. In order

to promote competition in the electric power sector, the Electricity Act 2003

(E. Act) mandates open access to the transmission and distribution network

for any supplier of electricity. Successful implementation of structural reform

requires both the hardware of technological advances in the power system and

the software of workable contractual relationships. Utilities need to make

efforts to identify such links / areas of high losses; there is still significant

uncertainty and differences over the real level of total as well as Transmission

and HT losses. Even two to three years after the establishment of the SERCs

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and the reforms process, there is still ambiguity over the real level of T&D

losses.

Review of Literature:-

Industry and Energy Department, World Bank (1996) in its research paper

“Power Sector Reforms in Developing Countries and Role of World bank”

discusses the experience of the Bank with the sector and the main drivers for

sector reform, the expected benefits of reform, the formulation of the Bank's

policy in this area, the principles and elements of reform, and the

methodologies of bringing about reform. The key message with regard to the

last point is that selection and design of the reform process and final sector

structure must be adapted to each country. Hence, the country's authorities

must make judicious choices among the many power sector restructuring

models and concomitant regulatory frameworks. The paper also discusses

issues of implementation lessons of experience, and the role of the Bank in

the reform process.

The precise dimensions of the governmental and sectoral reform may vary,

but in each case the reform effort needs to be governed by a set of clear

objectives. These are to (a) increase efficiency in generation through

competition, whenever possible, or through regulation based on efficient

enterprises and energy and other measures; (b) maintain service reliability by

setting strict rules to supply and variations from the technical standards (e.g.,

in voltage and frequency levels); (c) increase the security of supply in terms

of numbers of suppliers and types of energy resources; (d) improve

environmental protection by establishing clear rules in the construction and

operation of energy facilities, coupled with enforcement mechanisms and the

requisite penalties or incentives; (e) attract capital, domestic or foreign, by

establishing clear and stable" rules of the game" that relieve the government's

burden of funding the sector; and develop competition in the electricity

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services to customers, where viable, as a means of increasing the economic

efficiency of the sector.

The policy advisory group of Infrastructure Development Finance

Company Limited (IDFC), 1998 in its research paper “Power Sector Reform

in Orissa: Should and can it be replicated?” This research reviews this process

in Orissa, to examine its replicability for other states. It concludes that it

should be possible to transfer the reform process well beyond Orissa, subject

to a few safeguards. The objective of the privatisation process must be to

transfer the companies to the private sector, followed by obtaining a fair price

for government assets. At the same time it is imperative to insulate the

outcome against the possibility of renegotiations and default.

To reiterate, the replicability of the Orissa experience lies in ensuring that the

private sector is able to run the privatised entities, i.e., they are fundamentally

commercially viable. Doing this will require structuring distribution zones

properly and ensuring adequate financial support for the reforming entity, i.e.

the DISCOMs, during the transition process, so that it does not end up with an

unhealthy balance sheet, even when it is operationally efficient. It is also

essential to remember that people are as important as structure. To that end,

the selection and continuance of persons in charge of the process is of utmost

importance, as is the composition of the regulatory body. Subject to these

safeguards, which appear relatively easy to implement, it should be very

much possible to transfer the electricity reform process well beyond Orissa.

Asian Development Bank (ADB), 2001-02 in its research paper which acted

as Blue Print for “Power Sector Development” has identified the fault lines

and has found out the probable reasons which have emanated from:

• inadequate power generation capacity;

• lack of optimum utilisation of the existing generation

• capacity;

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• inadequate inter-regional transmission links;

• inadequate and ageing sub-transmission & distribution

network leading to power cuts and local failures/faults;

• large scale theft and skewed tariff structure;

• slow pace of rural electrification;

• inefficient use of electricity by the end consumer;

• lack of grid discipline

In view of the fact that addition of new capacity takes relatively longer time,

strategies have also been formulated to augment power supply in

short/medium run. These are:

• Increased generation through Renovation and Modernization (R&M)

of old stations.

• Utilisation of the surplus capacity of the captive power plants into the

grid

• Demand Side Management (DSM) to flatten the demand curves

(introducing time of day tariffs and metering).

• Introduction of a new system of matching time and load profiles for

different zones in the country.

• Energy Conservation (The Ministry is piloting the Energy

Conservation Bill, which, when enacted, will provide necessary legal

framework for promoting conservation and efficiency).

• Evacuation of power from the power surplus eastern region.

Sankar, T.L (2002), Advisor-energy, Administrative Staff College of India,

Hyderabad, in his work on “Power Reforms in India – the search for an

indigenous model for promoting competition” has identified the major

problems namely, the slow rate of addition to power generating capacity; the

lack of noticeable improvement in the governance, management and level of

service to consumers; the failure of efforts to induct the private sector into

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distribution; the inability to find a solution to the problem of subsidised

supply of power to agriculturists; the chaotic condition of governance of LT

distribution with, inter alia, the level of T&D losses remaining undetermined

and the annual loss reduction in the system being very slow; the

rationalisation or rebalancing of tariffs becoming a losing game because the

average cost of supply increases faster than the possible rates of increase of

tariffs; and the deficits accumulated over the years imposing an unbearable

interest burden limiting the capacity to raise funds in the commercial market.

He has also attempted to find out the followings:

• Should farmers, like other customers, pay the cost-of-service or the

average cost of supply?

• If farmers cannot pay the tariff and have to be provided power at

subsidised rates, what should be the level of subsidy?

• Who should pay the subsidy -- other users of power or all taxpayers

through the state government?

• Should the Government of India pay part or the entire subsidy as it

does in the case of fertilizer?

• If the tariff for agriculture is very low, is it worthwhile installing

meters for these consumers?

He has suggested of Revised Reform Programme (RRP). The RRP should be

taken as a comprehensive integral programme consisting of the following

elements, which should be implemented together.

Declaration that all new generating capacity would serve the consumers or

DISCOMs directly, abandoning the single-buyer model.

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Agricultural pumpsets and small households, which on socio-political

considerations have to be provided electricity at below the average cost,

should be supplied by an earmarked allocation from the generating plants

with the lowest generating costs. The quantity supplied thus as an

‘‘entitlement’’ should be specified by the government.

DISCOMs should be much smaller than currently contemplated and have

a maximum turnover of Rs. 6-8 billion.

All management of the distribution system below 11 kV should be

gradually shifted to the consumers themselves, with the requisite technical

and investment support coming from the DISCOMs.

Regulators should settle within one year the issues of relevance for long-

term multi-year tariff fixation, with explicit targets for T&D loss reduction

and for various other parameters.

Accumulated deficits and securitization and APDRP should be linked as

proposed above.

Abraham, P (2003), ex-power secretary, Government of India in his work on

Power Sector Reforms; Focus on Distribution has emphatically identified as

the one of the prime movers of the economic development. In his work he has

stated the non-availability of sufficient power and of good quality which is

going to be the single most critical constraint for the overall development of

the country.

Power distribution throughout India is plagued by:-

• Inadequate and deteriorating physical infrastructure

• Skewed tariffs, high T&D losses, theft of energy

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• Poor collection of revenue

• Dissatisfactory management practices and extreme consumer

dissatisfaction and more particularly the situation is acute in rural

areas.

The budgetary provisions of the state governments were reducing and the gap

between demand and supply was ever increasing and the gap between cost of

supply and tariff was widening. He stressed on the need for a comprehensive

accelerated reforms basing on the global experiences particularly from South

American Nations and USA, UK, Canada, etc.

He has impressed on the need of choosing right kind of reforms model among

the laid down models. The pre-requisites for carrying out such reforms and

privatization and the road map ahead for bringing the reforms to their logical

conclusion, so that a healthy and viable power sector can be created to

contribute substantially to the alround growth of our economy.

He has elaborated on the need of Government’s support for reforms, including

support during the transition period, organisational and financial restructuring,

and all other such issues which are germane for reforms.

Tongia, Rahul (2003), in his Stanford – CMU Indian Power Sector Reforms

Studies has analysed the following things: -

• Will reforms lead to economic viability of the system? Will this come

through tariff increase or cost control (or both)?

• What is the best role for the regulator, and are they equipped to be fair,

transparent, and independent regulators?

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• If we open the sector up to privatization (distinct from retail

competition), who will come in? Are there enough players? What

returns do they want or expect?

• Should rapid privatization of viable (urban) areas be done quickly, or

will such cherry-picking harm the overall system? To what extent

should there be pooling of costs (both at the generation level, and at the

retail level)? How fair and effective are such systems?

The analysis indicates several important ingredients for successful reform. For

starters, initial assumptions must be realistic and accurate, as must targets for

the participants. This was one of the major failures in Orissa, where the losses

were significantly higher than thought, and the growth of paying customers

did not materialize.

In addition, there needs to be sustained government support for reforms,

ranging from things varying from anti-theft legislation, to managing SEB

unions, to overcoming public opposition in general. In addition, if the newly

corporatised (or privatized) entities are to behave like companies, any gap

between average tariff and average cost of supply must be met through

explicit government subsidies (which, ideally, should be target driven and

time-bound).

At the end of the day, India’s reforms have thus far gone a fair ways towards

the ingredients necessary to reaching the goals of increased access, efficiency,

and viability, but they have not yet directly done so. These reforms, necessary

but perhaps not sufficient, will be the focus of enormous effort and

expenditure by the government, funding agencies, and companies in the

coming decade.

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Ranganathan, V and D, Rao Narasimha (2004), IIMB in their research

paper on “Power Sector Reforms in India” have analysed the progress of the

reforms in India which formally started along-with economic liberalization in

1991-92, though the impetus for private sector participation in the power

sector predates this. Despite aggressive reform policies in the 90s, private

sector participation was moderate at best, and the financial losses and cash

flows of State Electricity Boards (SEBs) reached crisis proportions.

They have outlined the stages of power sector reform, placing the

development of markets in context. They warn that in a situation of supply

scarcity, competitive markets – namely spot markets – can lead to price

increases and volatility, which will be slow to change due to short-term

supply inelasticity. More important is the need for bilateral trade under open

access to better exploit cheap, remote hydro and coal fuel resources in

northern India. They envision an environment of managed competition in a

bilateral market with regulated (capped) contract prices.

Shahi, R V (2005), currently the power secretary of India, in his work on

“Indian Power Sector; Challenge and Response” has highlighted the

infirmities in the power sector namely:-

• Power supply to Industry and Agriculture

• Poor quality of supply of power

• Lack of concern for consumers

• Highly skewed tariff structure

He has recognised the importance of manufacturing sector as it contributes

significantly to the growth of economy and helps in generating employment.

For them enabled to be competitive issues such as price of power, supply of

power without interruptions and quality of power are all equally important

and relevant. Risk perception of developers and lenders has been so high that

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in spite of best of private power policy formulated and notified in early

nineties, active responses were negligible. Having failed to get right and

adequate response from private sector, in order that vital infrastructure sector

does not get starved of funds for required expansion, during the 10th. Five

year plan public sector outlay was substantially enhanced. Continued inflow

of Government resources without commensurate commercial revival of this

sector would not only be an unsustainable arrangement, but as a matter of

fact, this may not even yield desired results.

Lesson learnt from Orissa’s privatization is that in India private sector today

is not equipped to handle adequately rural electricity distribution. It needs to

be recognised that consumers need not and should not wait for improved

services only when privatization happens. Competition is needed even within

the public sector on basis of performance benchmarks. He has maintained that

significant amount of improvement can be brought about even without any

substantial investment, just by way of toning up the operational maintenance

practices, better inventory management, training and development of people

and sharpening of work culture.

Significance of the Study: -

The present work aims to highlight the extent of reforms in power sector

commenced since Sept. 1991 to till date. It shows the comparative study of

rate of growth in generation, distribution and per capita consumption of power

along with several developed nations.

It also systematically studies the experience of ORISSA, which adopted

reforms process in late 1996 and its problems over these years. The findings

of the study will highlight the various aspects in this regard, which require

attention of the Govt.

24

Objective: -

Orissa is the first state in India to initiate reforms in the Power Sector. It has

left a benchmark for the whole of country and for a good experimentation.

Again in this backdrop, the objective of the project would be to study the

impact of reforms in the development of Generation, Transmission and

above all in the Distribution end. A concerted effort would be made to

have comparative analysis among different states that adopted reforms.

In an effort to achieve these objectives, the following steps would be

undertaken

- To ascertain the provision of quality power on demand to all

consumers.

- To study the different elements which determines the tariff structure?

To see whether there’s availability of alternatives to consumers.

- To verify the creditworthiness of power sector and if it is capable of

funding future investment needs.

- To check the extent of progress made in rural electrification.

- To measure the degree of transmission and distribution loss, if it’s in

the permissible limit.

- To systematically analyze the reasons for Orissa’s failure to become a

financially viable corporation.

- To make the interstate comparison of efficiency i.e. Orissa with Delhi

(Which adopted reforms in 2002) and to bring out the weakness of the

previous at the distribution end.

- To suggest alternatives to increase the cash flow without tariff hike.

- To examine the existing laws prevailing in different states to curb the

menace of power theft (Inter state comparison on state Electricity Act.)

25

Hypotheses: -

- To study if the power sector reforms have brought in commercial

viability in Power Supply Industry.

- To study if the power sector reforms resulted in the Supply of power at

Reasonable and Affordable Rate.

- To study if the power sector reforms have brought in Fiscal Discipline.

- To check if the introduction of OERC (Orissa Electricity Regulatory

Commission) has led to rationalization of Tariff structure and protected

the consumer’s interest.

Scope: -

The scope of present study has been with an eye on the process of power

sector reforms in India that was initiated in early 90’s. The present study is

restricted to few aspects i.e. a conceptual background on legislative aspect of

Indian Electricity Act. 1910 and Electricity Supplies Act.1948 and its reforms

that was initiated by amending them in 1991 and subsequent in Electricity Bill

2003.

It also empirically studies the various functional reforms carried out by

different state governments. It covers time series and cross section analysis on

trend scenario.

Limitation of the Study: -

The compilation and execution of the present study have to pass through

several constraints due to unavailability of adequate primary data. The

available data is very unsystematic which discouraged the systematic

26

treatment of data. Hence the study would have been more systematic if

detailed data would have been available.

Methodology: -

The present study is carried out by using some primary data and rest on

secondary statistical data. The data has primarily been obtained from Power

Management Institute, NTPC Ltd. POWERGRID, University Library -

University of Delhi, Corporate Office-GRIDCO/OPTCL and from several sub

divisional offices across India. Apart from this, several published journal viz.

TERI, Energy Watch, powerline, ADB Review and by interviewing some

senior personnel of different areas related to power industry. The method of

study includes the following:

-A survey of available literature on topic.

-Collection of data (Both time series and cross section)

-Analysis of published & Non-published Journals.

-Analysis of Primary & Secondary Data.

-Analysis of circulated Questionnaire.

-Classification and tabulation of data.

-Preparation of charts, graphs and schedules for proper presentation

-Suggestion and remedial measures for overcoming the problems faced by the

organization officials and scope for further study.

27

Organisation of the study

I. INTRODUCTION

II. POWER SECTOR REFORMS: A CONCEPTUAL FRAMEWORK

III. GROWTH OF POWER SECTOR

IV. POWER SECTOR REFORMS

V. RESTRUCTURING INITIATIVES IN ORISSA’S POWER SECTOR

VI. SOCIO ECONOMIC IMPACT ASSESSMENT OF POWER SECTOR

REFORMS

VII. CONCLUSION

• Summary

• Findings

• Suggestions

• Scope for further research

VIII. SCHEDULE OF ENACTMENTS

28

POWER SECTOR REFORMS: A CONCEPTUAL FRAMEWORK

Introduction

Electricity was entirely under the provision of the states as per the

Government of India Act 1936 but it was because of Dr. Ambedkar, who

was a member of the executive council for Power during 1942-46, Power was

included in the Concurrent List, Schedule VII of the constitution.

Recognizing the potential for the growth of power at that time, Dr. Ambedkar

felt the development of electricity in the whole country which cannot be left

to the provinces alone. According to Article 246 of the constitution,

parliament as well as the state legislatures has the concurrent powers to make

laws with respect to electricity. Whenever there is any conflict in the laws, the

central law shall prevail over the state laws. Dr. Ambedkar’s philosophy for

jurisdiction of central govt. over the electricity had withstood the test of time.

“The most challenging unbundling of all would be that of the

bureaucracy”

– Editors’ comment, India Infrastructure Report 2002.

Need For Reforms

Developing countries needs energy particularly electric power for social and

economic development. Many developing countries are unable meet their

energy demands of their economies because of the poor performance of their

existing plants and the shortage of adequate investment for new facilities to

meet the growth in demand.

Although the World Bank experience has been mixed, the performance of its

client countries electric power utilities has generally been poor to dismal. The

sub standard performance is usually reflected in low plant availability and

productivity, poor service to customers (Characterized mainly by energy

shortages leading to frequent blackouts and substandard system frequency)

29

and poor financial returns. The proximate causes of these problems are, on the

physical plant level, lack of readily available spare parts, scarcity or poor

quality of operating materials viz. lubricants, chemicals etc, poor maintenance

practices, inadequate training of operation and maintenance personnel and

lack of investment in necessary upgrading.

On financial front, government policies that have kept electricity tariffs well

below the cost of supply, combined with weak collection efforts by utilities,

have drained government budget resources instead of contributing positively.

It has thus been common for World Bank borrowers to request financing of

new plant at the same time as they maintain existing plant availabilities of less

than 50 percent.

A final problem for the power sector is on the institutional side, where

governments have controlled their power utilities as if they were departments

of the state and have used this control to pursue populist politics and social

policies that are incompatible with the commercial objectives. Governments’

inability to continue large subsidies to these utilities for operating purposes

and to mobilize funding for large investments needed for new plant to satisfy

the growing demand, with the private sector’s reluctance to invest in such

poor risk ventures, are leading to further deterioration in the performance of

electric utilities.

30

Table 1: Power Sector Performance: Gaps between Targets and Realities on Key Indicators in a sampling of regions and Countries

Note: SSA – Sub- Saharan Africa What is Reform?

Power sector reform consists of process of changes along four different but

inter-dependent axes: management, ownership, structure and regulation. The

structural change begins with the realization that a monolithic structure, often

established as part of a centrally planned or command economy is too

inflexible to respond to market forces and to provide appropriate incentives

for such responses. The government functions need to be broken into

a. That the government cannot relinquish such as the roles of setting

general policy & strategy, and sector regulation and supervision.

INDICATOR TARGET

REALITY

REGION / COUNTRY

Percentage of Population Served Utility management

• Customers per employee • Blackouts (hrs. / Yr.) • Load Factor • System Losses

Commercial Performance • Accounts receivable

(days) Financial Performance

• Return on assets • Self-financing ration

90%

150-250 7

70% 10-12%

30-45

8-12% >25%

5%

42 750 46% 35%

462

-19.8% 0%

SSA

Bangladesh Philippines

Nepal Bangladesh

Nigeria

India Jordan

31

b. Those that are subsidiary to the role of government and that can be

transferred, wholly or partially, to the private sector, such as

ownership, operation and management of energy facilities.

c. Those are not the core functions of the sector & that can be transferred

to other sectors such as research & development and construction and

manufacturing services.

The government’s function can be assumed by a ministry of energy, or state

energy commission or state supervisory agency. The ownership function can

be retained by the state, or it can be transferred to municipal or regional

companies or private sector. In any case the day to day, the day to day

management of the enterprises, even if fully state owned, should be exercised

by commercially operating entity. Finally the third category of functions

should be left to universities, research and development institutes, and

independent private sector companies.

Thus, the process of reform moves along two intertwined paths, one relating

to the other government actions and one relating to sector & enterprise

restructuring. The first path involves legal and institutional framework;

second involves commercialization and corporatisation of enterprises. It is

clear that the type of the regulatory framework and sector structure are closely

interconnected. The precise dimension of governmental and sectoral reform

may vary, but in each case the reform effort needs to be governed by a set of

clear objectives. These are to

a. increase efficiency in generation through competition. Or through

regulation based on efficient enterprises and energy use, conservation

and other measures.

b. maintain service reliability by setting strict rules to limit unreasonable

interruptions of supply and variations from technical standards ( e.g.

voltage and frequency levels)

32

c. increase the security of supply in terms of numbers of suppliers and

types of energy resources

d. improve environmental protection by establishing clear rules in the

construction & operation of energy facilities, coupled with

enforcement mechanisms and the requisite penalties or incentives

e. attract capital, domestic or foreign, by establishing clear and stable

“Rules of the Game” that relieves government’s burden of funding the

sector

f. develop competition in the supply of electricity services to customers,

where viable, a means for increasing the economic efficiency of the sector.

Role of Power Sector in Indian Perspective

The growth of economy calls for a matching growth for infrastructural

facilities where power is a major tool. Invariably power is an indispensable

unit of infrastructure, whose growth can never be compromised with. The

growth rate for the demand of power in developing economy like India is

generally higher than the growth of GDP (Gross Domestic Product). In order

to achieve a healthy growth rate of GDP around 8 per cent per annum, the

growth rate for power is prescribed to be more than 10 per cent per annum. So

far power sector has been greatly dependent on budgetary support and

external borrowings.

This thrust on generation, and even expensive IPP power, is best

characterized by Homi Bhabha’s oft-quoted statement,

“No power is as costly as no power”

The power generation grew from one MW in 1900 to 1363 MW during the

independence. After independence, the need for wide spread availability of

power was felt. Thus Electricity (Supply) Act, 1948 was enacted with an

intention to rationalize generation, transmission and distribution of electricity

in the country. The state electricity boards (SEBs) were allowed to start their

33

own generating stations except the nuclear power stations. To meet the

growing demand of power centrally sponsored Public Sector Enterprises like

National Thermal Power Corporation (NTPC) & National Hydro Power

Corporation (NHPC) were formed in 1975. Earlier being entrusted with

generation of power from coal and gas whereas later was asked to look after

the hydro based power generation. Power Grid Corporation of India Ltd.

(POWERGRID) was formed in 1989, to look after transmission of power and

to develop the interconnected grid system across the country.

NTPC was set up in 1975 with a view to promote and develop thermal power

in India. The corporation has grown geometrically in terms of both production

and quality power supply, within the country. The corporation has 13 coal

based thermal power projects and 7 gas / liquid fuels based combined cycle

projects. NTPC has adopted multi pronged growth strategy to become 40,000

MW plus company by the end of 2012. It has also acquired 314 MW of

captive power plant of SAIL through formation of joint venture with SAIL.

National Hydroelectric Power Corporation (NHPC) was set up in 1975 and

soon got the title of “Largest Producer” of hydro Power in India. NHPC has

commissioned several big hydro based electric generation projects across the

country including some in the difficult terrains. It also lends technical advice

to different state govts. in their projects.

Of course, hydro projects are attractive since, once constructed, they have

very low marginal costs (no fuel costs), and they offer reasonably high levels

of load control and quick start capabilities (subject to water availability).

However, Indian dispatch mechanisms do not fully account for marginal

cost pricing. While the ash content is high, the sulphur content is quite low,

reducing the need for clean-up technologies. No Indian coal plant today

incorporates Flue Gas Desulphurization (FGD) technology.

34

Nuclear power generation in India is in its infancy. It hardly meets 2.5% of

total generation. So Thorium, like Uranium 238 is the primary raw material

whose isotopes are available. (The primary form, or isotope, of natural

uranium, is fertile.

It can not undergo a fission reaction until converted into another element

through a nuclear reaction, such as in a Fast Breeder Reactor). Breeding is the

process of producing more fissile material from fertile than consumed to

sustain the reaction. India has the largest thorium reserves in the world, which

if converted to fissile material, could provide hundreds of thousands of

megawatts of power, for many, many centuries.

(Chidambaram, R. and C. Ganguly (1996). "Plutonium and Thorium in the Indian

Nuclear Programme)

Chart 1: Power generation mix during several plan

period

35

Table 2: Generation of Power – Sector wise & Compositions

ALL FIGURES IN MW X PLAN XI PLAN TOTAL

CENTRAL SECTOR

• Ministry of Power • Ministry of Coal • Department of Atomic

Energy • Ministry of Non-

conventional Energy Sources

23,000 210

1,220 4,055

23,500. 1,500 5,160 6,625

46,500 1,710 6,380 10,680

Total Central Sector

28,485

36,785

65,270

Total State Sector

8,300

10,600

18,900

Total Private Sector

9,400

13,500

22,900

Overall Capacity Addition (approx.)

46,000

61,000

1,07,000

36

Table 3: Hydel Potential – Global Scenario

Table 4: States with substantial undeveloped Hydro potential

State

Assessed (MW)

In Operation

(MW)

Under Construction

Balance (MW)

Arunachal Pradesh

50328 10.50 405 49912.50

U.P. / Uttaranchal

18898 1609.85 3453 13835.15

Himachal Pradesh

18820 3822.95 1926 13071.05

Jammu & Kashmir

14146 1394.25 469 12282.75

Sikkim 4286 84 519 3683.00 Karnataka 6602 2789 222 3590.60 Meghalaya 2394 185.20 000 2208.80 Mizoram 2196 000 60 2136.00

M.P. / Chhattishgarh

4485 898.50 1550 2036.50

Kerala 3514 1799.50 30.25 1684.25 West Bengal 2841 300.50 936 1604.50

Manipur 1784 105 90 1598.00 Nagaland 1574 75 24 1475.00

Orissa 2999 1837.50 66 1095.50

COUNTRY Exploitable potential

Installed capacity % of potential utilised

NORWAY 47,000 27,360 58

CANADA 1,60,000 65,678 41

BRAZIL 17,000 52,427 31

CHINA 3,10,000 56,000 18 INDIA 1,50,000 23,488 17

37

Table 5: Inter-regional Links under Operation

Name of the Link

Regions inter-

connected

Capacity (MW)

HVDC Links

Vindhyachal HVDC back to back West and North 500 Chandrapur HVDC back to back West and South 1000 Gazuwaka HVDC back to back East and South 500

AC Links

Korba-Budhipadar 220kv 3 ckts West and East 450 Balimela-Upper Sileru 220 kv S/c East and South 200

Kolhapur-Belgaum 220kv D/c West and South 300 Lower Sileru and Burgur West and South 100

Dehri-Sahupuri 220 KV S/c Karmnasa-Sahupuri 132Kv D/c

North and East 200

Biharshariff-Sarnath 400 kv D/c North and East 500 Birpara-Salakati 220 kv D/c East and North-East 100

Auraiya-Malanpur 220Kv D/c North and West 200 Bongaigoan-Malda 400 Kv D/c North-East and East 800

Total

4850

38

Chart 2: Constituents of Financial Parameter

REASONS FOR POOR FINANCIAL HEALTH OF SEBs/STATE UTILITIES

Negative Returns on investments

• Skewed tariff system subsidising domestic and agricultural consumers at expense of industrial consumers

Average cost of power Average Revenue

• Inadequate R&M investments resulting in less than optimal PLF

Low PLF

• Technical losses account for about 15-20% of these losses

• Commercial losses account for 20-25%

High T &D losses

• No firm policy on disconnection

• Varies widely across stats (lower in Tamilnadu and higher in Bihar)

High Accounts Receivables

39

Power Sector in Pre-reform Period (1961-90)

Soon after the independence, parliament enacted Electricity (Supply) Act,

1948 bringing the entire power industry in the country into the fold of public

sector, establishing separate SEB (State Electricity Board) as a vertically

integrated utility in each state and setting up the Central Electricity Authority

(CEA) as the apex technical body to oversee the power industry at the

national level. But till 1970s the development of power sector was wholly the

responsibility of the individual state governments. The government of India

decided to play a positive role in augmenting the power generation in the

country by establishing NTPC & NHPC in 1975.The idea was to set up large

thermal power stations and optimally located large hydropower stations

whose benefit can be utilised by the regions of the states as well. From the

above table, we can see that central investment in power sector started rising

from the 1980s. But the state governments accounted for the major share of

the outlay on the power sector and allocations under the state plans were

highest among all sectors of development. Because of certain historical

reasons, a small share of generating capacity under private ownership was

seen in the cities of Ahemadabad, Mumbai and Calcutta.

In the early 80s, Rajadhyaksha Committee (Committee on power) stressed on

the need for higher investment in the areas of Transmission & Distribution

(T&D) was required to overcome the problem of high technical losses.

Indian Economy and Growth of Power Sector

Electricity reforms in India formally took off along with the economic

liberalization in 1991-92.Prior to this the pattern of investment in the power

sector looks like this as mentioned below.

40

Table 6: Plan Outlay On power Sector (1961-90) Centre States & UTs Total Outlay

(Rs. Cr.)

% of Plan outlay

Outlay (Rs. Cr.)

% of Plan Outlay

Outlay (Rs. Cr.)

% of Plan Outlay

Third Plan (1961-66)

109 3.0 903 23.1 1012 13.5

Fourth Plan (1969-74)

447 5.0 2001 28.5 2448 15.4

Fifth Plan (1974-79)

825 4.1 6469 33.4 7294 18.6

Sixth Plan ( 1980-85)

4725 10.0 14,540 28.9 19265 19.8

Seventh Plan (1985-90)

11,051 11.6 23,222 27.5 34,272 19.0

Source: Planning Commission – respective plan documents Table 7: Installed Power Capacity 1950 to 2000 (MW) Year Public Non-utilities Total 1950-51 1,710 590 2300 1970-71 14,710 1560 16,270 1990-91 66,100 8,600 74,700 2001-02 1,04,900 16,100 1,21,000 Table 8: Installed Capacity (MW) At a Glance Ownership/Mode Hydel Steam Gas Diesel Wind Nuclear State 22636.02 36302.00 2661.70 582.89 62.86 0.00 Central 3049.00 21417.51 4419.00 0.00 0.00 2720.00 Private 576.20 4411.38 4082.40 551.94 1444.60 0.00 Total 26261.22 62130.89 11163.10 1134.83 1507.46 2720.00 % of Installed Capacity

25.03 59.22 10.64 1.08 1.44 2.59

Source: Annual report (2001-02) on working of SEBs by Planning Commission

41

Table 9: Physical Performance (At the All India Level) Year Plant Availability

(%) Plant Load Factor (%)

T&D Losses (%)

1996-97 79.00 64.40 24.53 1997-98 79.40 64.70 24.79 1998-99 78.70 64.60 26.45 1999-2000 80.30 67.30 30.80 2000-01 80.50 69.00 29.90 2001-02 NA 69.90 27.80 Source: Annual Report (2001-02) on working of SEB by Planning Commission

42

Power Sector during Reforms Period (1992-2002)

The government realised that the gap between demand and supply of power

was widening and requirements of future expansion and improvement of

power sector cannot be fully achieved through Public resources alone which

augmented the need for encouragement of private players in generation,

transmission and distribution of power. The most important factor was that

the state electricity boards were fast moving towards bankruptcy. In the

Common Minimum National Action Plan for Power (CMNPP), this was

approved by chief ministers in the conference convened by Prime Minister in

1996 which ushered in the comprehensive reform programme for power

sector, including reforms in the distribution sector. The resolution passed in

the CMNPP includes:

1. Establishment of Central Electricity Regulatory Commission (CERC)

and the State Electricity Regulatory Commission (SERC) in each state

in time bound manner.

2. Rationalization of retail tariff, under which no sector shall pay less

than 50 per cent of the average cost of supply and tariffs for agriculture

should not be less than fifty paise per unit and should be increased to

50 per cent of the average cost in not more than three years.

3. Finalization of National Energy Policy.

4. Gradual private participation in distribution, initially in one or two

viable geographical areas covering both urban and rural areas and

extend to other parts of state gradually.

5. Restructuring and corporatisation of SEBs and make them function on

commercial basis.

6. Improvement in plant load factor (PLF).

7. Compulsory metering of all sub-stations and all major feeders, all new

connections and all connections including agricultural connections

should metered by the year 2002.

43

8. Compulsory energy audit for all consumers.

9. Evolvement of a national policy on hydro power development

10. Encouragement for co-generation and captive generation.

At the time of approval of CMNPP, the power sector was full of hopes as

country was expected to add about 10,000 MW of generation capacity every

year and 50,000 MW in next five years out of which three fourth would be

coming from the private sector.

In the wake of this large number of Memorandum of Understanding (MOUs)

were signed between the state government and different prospective investors.

As many as 58 schemes having a capacity of 30,000 MW (Approx.) were

cleared by CEA.

The single most important factor which became a stumbling block in

attracting foreign direct investment was the fact that the SEBs were on the

verge of bankruptcy. They had defaulted in payment to central PSUs for

supply of coal, power etc. The industry was characterized by lack of

efficiency, excessive manpower, poor project management, irrational tariffs,

and high proportion of Unmetered supply, large scale theft of power in

collusion of SEB staffs, poor billing and collection mechanism, perennial

problems like theft of cable, wires etc., non payment of government dues and

even resistance to disconnection of supply for non-payment of dues, poor

customer grievance redressal mechanism by SEBs.

Due to ailing state finances, state governments did not show any willingness

to stand guarantee for payment for power purchased by the SEBs. In 1992, the

government of India offered counter guarantee to few fast track projects but

none of these could reach financial closure. Investors had to face formidable

procedural hurdles; negotiations had to be carried out with numerous agencies

both at centre and state level. Since the raw material for thermal power being

44

coal, so IPPs wanted to ensure the smooth and timely supply of coal. But both

coal companies and railways, which transport the coal, expressed their

unwillingness to enter in to any legally enforceable fuel supply agreements.

The public perception was that power supply from IPP is costlier than from a

similar publicly owned generating station which led to the reopening of the

Power Purchase Agreements (PPAs). Added to this was the bureaucratic

delay. Single window mechanisms proved to be ineffective. This was not

conducive in attracting the private investment in the power sector. The

questions were raised about the Government commitment to power sector

reform especially for the private players.

Private players did not show any interest in power transmission. The scope

available for the owner of a transmission line to cut costs or maximize

revenue is remote because the owner has no control over the flow of power in

his line. In developed countries also investors did not show much interest in

erecting transmission line.

The private sector has to play an important role in power distribution. The

sizeable backlog of investment required to reduce technical and commercial

loss and keep pace with load growth. More importantly improvement in

operational efficiency and quality of service, proper billing and collection

mechanism, greater responsiveness to consumer needs will be the principal

gains from private ownership and management of distribution network. A

successful distribution reform holds the key to success in restructuring of

power sector.

45

Table 10: Public Sector Investment In power 1992-2002 Centre States and UTS Total Investment

(Rs. Cr.) % of Plan outlay

Investment (Rs. Cr.)

% of plan outlay

Investment (Rs. Cr.)

% of Plan outlay

Eighth Plan

30,426 11.0 46,251 24.0 76,577 15.8

Ninth Plan

53,299 10.8 70,926 18.9 1,24,526 14.5

Note: In the ‘investment” column, expenditure is shown for eighth plan and outlay for ninth plan. Source: Planning Commission, Annual Report (2001-02) on the working of State Electricity Boards and Electricity Departments. Annexure 2.3 & 2.4 Table 11: Capacity Addition 1992-2002 Central

Sector State Sector

Private Sector

Total Central Sector

State Sector

Private Sector

Total

Eighth Plan (1992-97) Hydro 3260 5860 162 9282 1465 795 168 2428 Thermal 8498 9010 2646 20,15

6 6252 6041 1262 13,555

Nuclear 1100 - - 1100 440 - - 440 Total 12858 14870 2810 3053

8 8157 6835 1430 16423

Ninth Plan (1997-02) Hydro 3455 5815 550 9820 540 3912 86 4538 Thermal 7574 4933 17038 2954

5 3084 5538 4975 13597

Nuclear 880 - - 880 880 - - 880 Total 11909 10748 17588 4024

5 4504 9450 5061 19015

Source: Planning Commission, Ninth Plan, Vol II, Chapter 6, Table 14 and Draft Tenth Plan, Vol 2, Table 8.2.2

46

From the above two figures namely Public Sector Investment in Power and

capacity addition during the ten year period led us to this conclusions-

1. The central government started spending more money on power in

comparison to previous years and a substantial hike in central outlay in

ninth plan can be seen.

2. Actual capacity addition fell seriously short of target in both Eighth

and Ninth Plan.

3. Private sector participation in capacity addition was worse among these

three. In eighth plan actual capacity addition almost 50% of the target

set but in ninth plan it was even less than 30% of the target set.

4. Capacity addition of hydro power in state sector was steadily

increasing & phenomenal rise can be observed in ninth plan.

5. Actual capacity addition fell seriously short of target both in Eighth

and Ninth Plan periods.

In short, the post reform performance shows that far from any improvement in power situation, this sector suffered severe setback.

Table 6: Electricity – GDP Elasticity in India Elasticity

First Plan 1951-1956 3.14 Second Plan 1956-1961 3.38 Third Plan 1961-1966 5.04 Fourth Plan 1969-1974 1.85 Fifth Plan 1974-1979 1.88 Sixth Plan 1980-1985 1.39 Seventh Plan 1985-1990 1.50 Eighth Plan 1992-1997 0.97 Ninth Plan 1997-2002 0.75

Calculated and compiled from data from the Planning Commission and Ministry of Finance (Economic

Surveys) While many Plan documents claim growth targets of 40-60,000 MW for the

coming 5 Year Plans, and even segment these into state, central, and private,

it is unclear how such growth will be financed or sustained in the current

47

operating environment. Assuming a target of 100,000 MW expansion, which

would less than double the per capita consumption given the increase in

population over 10 years, the estimated investment would be 150 billion US$,

using the rule of thumb (coal-centric) that 1 MW of capacity addition requires

1 billion dollars investment for generation, and half that more for T&D. 15

billion dollars per annum is almost 4% of the GDP, a number too high for

domestic savings rates and budgets alone. This was one of the prime reasons

that the government wanted foreign investment in the power sector, making

this a central feature of the 1991 reforms.

(India’s development is largely based on Soviet-style 5 year plans, and a few

Annual Plans in between. Critics state that too much effort is placed on Plan

(largely capital) expenditure, and not enough focus is there on operating

expenditures, like maintenance, monitoring, enforcement, analysis, etc. In

most states, if a consumer needs a new connection, they have to pay non-

trivial connection fees if the lines need to be extended. The charges vary by

state. Part of this may be due to poor metering. Older electromechanical

meters have a threshold below which they fail to register consumption. Newer

electronic meters only became available in the 1990s.)

(The Indian (British-based) system was supposed to have a near permanent bureaucracy, giving

stability as the elected politicians shifted over time. This is in contrast to the American system, where

the new executive office brings in a new (but fixed term) operating staff for the various departments.)

48

Electricity Bill 2001(Power for all by 2012)

There is a major revamping of India’s power sector planned via the Electricity

Bill 2001, which is in Parliament but has not yet been passed. This legislation

was originally planned for 2000, and was renamed for 2001, but the act was

ratified by the parliament only 2003, referred as Electricity Act. 2003.

Main Features of Bill include

1. Formulation of a National Electricity Policy by the Govt. of India

2. Strengthening anti-theft laws

3. Generation free from licensing except for hydro units

4. Requirement of techno-economic approval done away with

5. Captive generation free from controls

6. Open access to transmission lines

7. Setting up of State Electricity Regulatory Commission (SERC)

mandatory

8. Open access in distribution to be allowed by SERC in phases

9. Retail tariff to be determined by regulatory commission

10. Trading a distinct activity permitted with licensing

11. Establishment of Appellate Tribunal

This would be a major bill, revamping the 1910 and 1948 Laws, and

extending reforms further. Fundamentally, it moves the country towards

power markets, but it provides very little detail on the operations of such a

system, e.g., the role of any Independent System Operator (ISO). It states that

Regional Load Dispatch Centres will be responsible for grid operations, and

failing their abilities or powers, the Central Transmission Unit (i.e., Power

Grid) will take over this role. The Electricity Grid Code referred to in the bill,

as formulated today (Power Grid 2002), states that these entities will not trade

power, but only facilitate power transactions. The Power Trading

Corporation, though designed to trade power, is not set up as an ISO. Both the

Bill and the Code indicate Regional as well as State Load Dispatch Centres.

49

This appears to be a poor design, as the synchronous grid should not operate

with such granularity.

The Electricity Bill 2001 has a strong focus on bulk (High Tension)

consumers, who can get open access to generators (captive or IPPs).

However, it doesn’t indicate how much surcharge the utilities can pose, for

the losses they incur (loss of paying customer) (Mahalingam 2002). This

tension, over paying customers that sustain the cross-subsidies of today, is

one of the major issues facing the Indian power system.

Table 12: Tenth Plan Power Sector Outlay (2002-07) Ministry/Department Outlay Centre Power 1,43,399 Coal 8,008 Atomic Energy 25,577 States & UTs 82,224 All-India 2,59,208 Note: The outlays of Ministry of Coal and Department of Atomic energy are for ‘Power programmes’ Source: Derived from Planning Commission, draft tenth plan, Vol 2, Annexure 3-A to 3-C Table 13: Financing Pattern of Central Sector outlay in Tenth Plan (Rs. Crore at 2001-02 prices)

Note: 1.The outlay under Atomic Energy covers both power and R&D programmes. In the Tenth plan Rs. 25577 are for power 2. The budgetary support for coal includes Rs. 1257.4 cr. And Rs. 8007.6 cr. Under ‘Ninth Plan Realisation’ and ‘Tenth Plan Projections’ respectively for power. (Neyveli Lignite Corporation). Source: Planning Commission, Draft Tenth Plan, Vol 1, Annexure 3-B.

Budgetary Support Total Outlay Internal and Extra-budgetary resources

Ministry/ Dept.

9th. Plan Realisation

10th. Plan Projection

% Increase

9th. Plan

Realisation

10th. Plan

Projection

% Increase

9th. Plan Realisation

10th.Plan Projection

% Increase

Atomic Energy

6771 21550 218.3 1671 10820 547.5 8442 32370 283.4

Coal 2233 1050 -53.0 14623 30541 106.0 17058 31591 85.2 Power 14907 25000 67.7 29785 118399 297.5 44692 143399 220.9

50

Private Sector Participation in Generation

The reform policy introduced in 1991 allowed private sector to set up

companies to act as licensees, generating and distributing power, or simply as

generators. Up to 100% foreign equity participation was permitted, with a

maximum debt to equity ratio of 4:1. The return on foreign equity was

protected in foreign currency and numbers of tax concessions were also made.

In order to determine tariff for the purchase of power, a notification, which

laid down the guidelines for a two part tariff, was issued. The main features of

the notification were:

1. 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.

2. A maximum of 16 per cent RoE was allowed to be included on the

tariff (this was protected against fluctuations in the exchange rate)

3. Fixed cost would be recovered at a PLF of 68.5% (equivalent to 6000

hours of operations) in case of thermal plants, and at an availability

factor of 90% in case of hydroelectric plants. The normative PLF for

thermal plants was revised to 75 percent in February 1997.

4. As an incentive, a maximum of 0.7 per cent additional RoE could be

given for every one per cent increase in PLF or availability.

51

Clearance & Approvals

In order to clear a thermal project, the CEA requires an approval from the

state government and electricity board concerned, clearance of water

availability, and fuel linkage approval from the petroleum and natural gas

ministry or from the coal ministry. Projects also require environment

clearance and chimney height clearance from the National Airport Authority

of India.

Fuel supply and Transportation: Fuel supply has become a contentious issue

as the supply 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 to the lack of experience with such contracts, particularly

with regard to the evaluation and quantification of the associated risk and

premium. Further the Indian Railways, the principal carrier of fuel, is

unwilling to assure uninterrupted supply. The IPPs insist that the penalty for

supply interruptions should cover the loss of revenue (Fixed cost component

of tariff) attributable to the default in fuel supply; some of them suggest that

the penalty could be on the basis of the additional cost incurred in procuring

fuel from alternate sources. PSUs and Railways however contend that it

should be related to the value of the fuel not supplied. In the absence of any

satisfactory resolution to this problem, financial closure is getting delayed

because the lending institutions, understandably, are reluctant to bank on risky

fuel supply agreement (FSA).

52

III. Growth of Power Sector Global Perspective

Many countries have started reforms in the power sector before India

embarked on reforms. Notable among them were UK, USA, and Latin

American countries like Chile, Argentina, Peru, Columbia, EU Nations and

Australia. Their reforms programs were based on country’s governmental

structure, demographics, socio-economic and political environments and

resource availability. But it was amply clear that those countries had

undertaken restructuring electric utilities were for improving the efficiency,

reducing tariff and to provide better quality of service to consumers, through

competition and consumers would gain from efficiency gains in generation,

transmission and distribution. Restructuring also led to the removal of certain

problems like load shedding, blackouts, and high degree of T&D losses which

includes theft of energy, etc. The private investment has become essential to

pump in additional generation, improvement in transmission and distribution

improvements.

International Scenario of Power Sector

1. United Kingdom

UK was pioneer in unbundling government owned vertically integrated

electric utility and privatizing the same. It also introduced competition in

generation through power pool and a spot market. Initially there was

resistance from opposition parties but it became popular with electorates. The

small investors saw an opportunity to make investments and earn good

returns. The British Model became the bench mark of reforms and it provided

a platform for other countries to follow the same.

53

Privatization of Power Industry

The electricity industry was under public ownership from 1948 to 1990. The

Central Electricity & Generating Board was in charge of generation and

transmission. The Board was engaged in selling the bulk electricity to 12 area

distribution boards. This monopoly resulted in excessive capital costs, over

dependence on high-cost indigenous coal, low productivity growth, low return

on assets and inefficient consumer redressal. The Electricity Act 1989 paved

the way for privatization of electricity industry in UK. The industry was

segregated in to four functions namely Generation, Supply, Transmission &

Distribution. Open access was thus introduced. The basic underlying

objective was to foster retail competition by allowing increasing number of

consumers to shop around for the best service.

The initiatives in this regard were taken as early as 1980s, which were

comprised

1. Generation and Transmission was segregated and all the generating

stations were made in to separate companies.

2. Two generation companies and regional distribution, which was owned

by distributors, were floated on the stock market.

3. A centrally co-ordinated power pool, which acts as a spot market was

created.

4. Generators compete to dispatch to the power pool as well as to enter in

to bilateral contracts with distributors/retailers and end users.

5. Retail competition was allowed for large users.

6. All generators had the open access to the transmission network to

ensure retail competition.

All power utilities were unbundled into generation, transmission and

distribution segments. Generation companies except nuclear generation

companies and distribution companies were privatized; a central pool was

created, which enables the companies to dispatch the power to the pool or

54

even to enter bilateral contracts with distribution companies as well as large

end users. The principle of competition was introduced at every stage and

open access was created for transmission network on payment of wheeling

charges which also allowed retail competition.

Labour productivity doubled in the first six years. There was a market shift in

consumption from coal to natural gas. The prices of coal delivered to power

fell by 20 percent in real term and unit costs fell by about 50 percent.

Privatization resulted in a cost reduction of about 5 to 7.5 percent of prices or

an extra 40 percent return on assets. The price of power fell almost by 20

percent in real terms and unit cost fell by about 50 per cent. Privatization

resulted in a cost reduction of about 5 to 7.5 percent of prices or an extra 40

percent return on assets. The price of power fell by about 20 percent.

Chart 2: Load Duration Curve

55

The Pool

The most innovative reform was the pricing of power sold by the generation

to the Regional Electricity Companies (REC), who are the distributors or

bulk users. In UK, all generators sold power to a pool operated by the national

grid company. The generators would bid to supply power in half hour slots

during a day. The dispatch was done on the basis of merit order of these bids,

as per the demand. The main reasons for establishing the pool were:

1. The advantage of minimal change from pre-privatization arrangements

2. The advantage of transparency bidding

3. The advantage of substantial market, a new supplier can enter

4. The belief that an efficient market would be characterized by a uniform

price for all participants equal to marginal cost.

In order to protect themselves against the potential variability of pool prices,

generators and suppliers entered in to a series of short-term contracts which

allowed both parties to manage the risks caused by uncertainty about pool

prices. Initially pool prices fluctuated sharply and a review had shown that it

was subject to severe manipulation and it came in for lot of criticism. It

included lack of transparency regarding the price determination, lack of

proper competition, lack of demand side participation and lack of flexibility to

adapt to changing circumstances.

National Electricity Trading Arrangements (NETA)

In order to overcome the above problems a New Electricity Trading

Arrangement (NETA) was introduced to replace the pool system with

forward future market and short term spot market and balancing mechanism.

The forward contract market is where customers and distributors can enter

into bilateral contracts for electricity directly with generators. The prices will

be negotiated and the contracts will be “take or pay” contracts. The future

56

markets are legally binding arrangements between a buyer and a seller to

deliver and take delivery on a specified future date a quantity of electricity at

a price agreed today on the day of the contract. A short-term spot market

where simple offers and bids for electricity, including demand side reductions

can be traded.

A balancing mechanism will be used by the National Grid Company (NGC)

to balance actual supply and demand on the system as well as to solve

transmission constraints. This market will open 3 to 5 hrs ahead of the

moment of delivery and operate up to the moment of delivery. Through this

mechanism, NGC will be able to contract for increases or decreases in

generators’ output or decreases in customer demand.

The British model demonstrates that unbundling is feasible and generation,

transmission and distribution can be separated from one another. It shows that

it is very important that competition needs to be introduced in power market

by structural reform at the start of the reform process itself. The power sector

reform can yield substantial productivity gains.

The government and regulator must expect to face unanticipated challenges,

during the transition period. The sequencing and the timing of the reforms are

critical. The government’s full and sustained commitment is vital to the

success of its reform programme, as the government must resist tendencies by

some power entities to pre-reform structure.

The UK experience has considerable relevance to the developing countries.

The main development priorities of the power sector in developing countries

are to meet rapidly increasing demand for power and to expand access to

electricity. Power reform in developing countries tends to be driven by failure

to meet these priorities.

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From UK experience it became clear that it is possible to introduce and foster

competition that permits consumers to buy directly from producers with

Transmission Company as just for fee, a carrier like road transport business.

2. United States of America (USA)

In a federal country like USA the situation varies across states. The electricity

industry in the US comprised about 200 vertically integrated privately owned

utilities, over 4000 non-utility generators, about 3000 distribution utilities

including local city controlled utilities and rural electric cooperatives. The

existing legislative framework for regulating electric industries has Federal

Energy Regulatory Commission (FERC) at the national level and separate

regulatory commission at state level. While most regulatory functions are

exercised at the state level, the federal agency is responsible for regulating

mainly the wholesale trade across the states.

In the US, the Federal Energy Regulatory Commission (FERC) is

promoting an agenda for open access to transmission, and a number of states

and utilities are considering restructuring the industry to set up power pools,

separate generation from other functions and provide better customer service.

Thirteen states in the US have already enacted electric industry restructuring

legislation, five have issued regulatory orders, and all the rest are considering

the issue.

The California Power Crisis 2000-2001

“Its problems are largely manmade.”

—Newsweek Magazine, April 3, 2001, p. 23

The California power crisis is so sudden and serious that it is prompting

policymakers in many countries as well as other U.S. states to look for lessons

that can be applied to the reform of their own power sectors. Concerned

policymakers around the world are asking: If things can go so badly wrong

58

with a reform that did not involve wholesale privatization of the electricity

supply industry in such a rich and sophisticated economy, what are the

implications for much less well-endowed countries embarking on the full

menu of reform including privatization?

When a power sector reform like California’s fails, political authorities are

inevitably under strong pressure to “do something” to solve the crisis. In a

special session of the California legislature called by the governor, legislators

introduced more than 75 bills intended to solve one or more aspects of the

crisis. Unfortunately, quick-fix “solutions” often lead to outcomes that can be

inconsistent with the original reform objectives and can produce outcomes

that are even worse than the conditions that triggered the reform. In 2001 the

California and federal governments had proposed or undertaken actions which

include the following:

Price caps. The Federal Energy Regulatory Commission (FERC) imposed

price caps that may deter the investment needed to overcome the current

supply shortage.

Forced sales. The U.S. Secretary of Energy issued several orders that

required generators and natural gas suppliers to continue selling to non-

creditworthy California buyers.

Government energy trader. A new state law authorizes the state government

to spend up to $10 billion on the state’s credit to purchase wholesale

electricity that can be resold to the three large privately owned utilities.

“Nationalization” of the grid. The State of California may become the new

owner of the portion of the high-voltage transmission grid currently owned by

the three large privately owned utilities.

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“Balkanization” of wholesale electricity trade. The state’s Assembly has

passed a bill that would make it difficult to export electricity produced from

new generating plants located in California to buyers outside the state.

Many elements of the California reform package are peculiar to a complicated

and unusual market design that was the outcome of a political compromise

reached by various stakeholder groups. Many of these features will have no

immediate, or even near-term, relevance for most developing countries.

In developing countries, the California power crisis may be creating the

impression that power reform is too risky. The power crisis in California does

not justify this conclusion. For many developing countries, the status quo in

the power sector is the riskiest alternative of all. The status quo often creates a

drag on economic growth through inadequate and poor-quality power supply.

In addition, limited government funds are frequently diverted to the power

sector that would otherwise be available for schools, clinics and roads.

Therefore, most countries simply have no alternative to a substantial and basic

reform of the sector that almost always requires restructuring and

privatization. But like all human endeavours, power sector reform can be

done well or done poorly. The principal lesson of California is that good

intentions are not enough. Any reform must pay close attention to starting

points, the particular problems that need to be solved, and the appropriateness

of the path selected for solving these problems.

The paper is organized into three parts. It begins with an overview of the key

features of the 1998 California power sector reform: how it differs from

reforms elsewhere, the events and actions that have put it in a crisis mode, and

the main lessons that can be learned from the crisis.

Following the overview, the main text is divided into two parts. Part I

discusses in depth the lessons learned, which concern mainly the

establishment and regulation of a mandatory, wholesale power market based

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on spot pricing. Since this is not a near-term option for many developing

countries, the paper also describes other, more-limited forms of competition

that may suit their situations. Although privatization was not an element of

California’s reform, the state’s experience does indirectly provide important

lessons for the privatization and regulation of distribution enterprises and new

market entities in developing countries.

Part II details the specific reforms initiated in California, reviews the factors

that led to the crisis, and examines whether the crisis could have been avoided

through better market design and management. The paper draws on numerous

sources such as published articles, reports and websites, as well as the

working experience of World Bank staff in numerous countries.

The Nature of the Reform

Key Features

• The three privately owned utilities were “encouraged” to sell off their

generating plants but without any vesting contracts to buy back the

output of plants.

• In return, the utilities were allowed to recover their “stranded costs”

(i.e., anticipated above-market costs) associated with the two high-cost

nuclear power plants and the state-mandated purchases of power from

certain IPPs through a “competitive transition charge” on consumers’

electricity bills.

• The state government mandated a 10- percent reduction in retail rates.

Retail rates were frozen for four years or until stranded costs were

recovered. Actual consumer bills went down little because the

reduction in rates was largely offset\ by the competitive transition

charge.

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• Retail (residential, commercial and industrial) customers were given

the right to choose alternative electricity suppliers.

• A non-profit, Independent System Operator (Cal ISO) was created to

operate the transmission facilities owned by the private utilities (about

75 percent of the state’s high-voltage grid). The Cal ISO also operated

a bid-based real-time energy market as well as several other markets to

acquire grid support services (i.e., ancillary services).

• A separate Power Exchange (Cal PX) was created to operate a bid-

based, centralized market for forward (day-ahead and day-of) power

sales. The two largest private utilities were required to buy and sell all

of their electricity through the Cal PX.

• Both the Cal ISO and Cal PX were governed by large boards, each of

which was made up of more than 30 stakeholder and non-stakeholder

members.

• The retail electricity rates of individual privately owned utilities

continued to be regulated by the CPUC. Even though the Cal PX and

Cal ISO were under the regulatory jurisdiction of FERC (the national

electricity regulator), the CPUC and the state government had

substantial de facto influence over their actions. The two regulatory

entities, the CPUC and FERC, sometimes issued conflicting orders.

• The coverage of the reform was incomplete. Municipal utilities were

given the option of not participating in these new arrangements. In

general, they chose not to participate.

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How the California Reform Differs from Other Power Sector Reforms

• Initially, the major private distribution companies were not allowed to

buy outside of the spot markets. (No vesting or forward contracting

was allowed.) Hence, they were totally exposed to the price volatility

of the Cal PX spot markets.

• Distribution companies and others who serve retail customers were not

required to own or have under contract sufficient generation capacity

to meet their peak demands.

• No provision was made for pass-through of wholesale purchase power

costs to retail rates until full recovery of stranded costs or March 2002

(whichever came first).

• The complicated design involved multiple, sequential wholesale

markets operated by two new separate entities (the Cal PX and the Cal

ISO). In other U.S. regions, the ISO and PX are combined in a single

entity.

The Reform Process

The reform operated by “political consensus.” The final version of the

reform package reflected a compromise among competing

stakeholders. It was incorporated in a bill that was passed unanimously

by the California legislature.

Criticisms of the final design by outside power sector reform experts

were generally ignored by state and national political and regulatory

authorities.

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The Crisis

• The highly contentious sitting and permitting process for new

generating plants blocked the installation of any major new generating

plants for more than 10 years. California’s installed generating

capacity declined by about 1,200 MW between 1997 and 2000.

• Wholesale markets operated by the Cal PX and Cal ISO worked

reasonably well for the first two years (1996–98) while the initial

surplus of generating capacity disappeared. Less than 2 percent of

residential customers exercised their option to pick new electricity

suppliers because new suppliers could not offer substantial reductions

in consumers’ electricity bills under the rate freeze and competitive

transition charge during the reform transition period.

• A shift in market fundamentals occurred: large increases in electricity

demand in California and neighbouring states, reduced availability of

hydropower in California and the Pacific Northwest, and big increases

in the prices of gas and pollution permits to emit nitrogen oxides

(NOx).

• Wholesale spot prices skyrocketed starting in the spring of 2000.

California utilities paid around $11 billion more for electricity in the

summer of 2000 than in the summer of 1999. Similar wholesale price

increases in neighbouring states had less impact because, unlike

California, only 5 to 10 percent of their overall supplies are purchased

on the spot market.

• Mandated rolling blackouts throughout the state since December 2000

seriously disrupted the state economy (the sixth largest in the world).

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Even more widespread blackouts are expected in the upcoming

summer.

• Some evidence indicates that the growing shortage of generating

capacity, combined with certain features of the complex wholesale

market design, may have allowed some generators to exercise market

power.

• Limited or no pass-through of wholesale costs to retail customers has

forced the two largest private companies to incur around $12 billion in

unfunded liabilities since April 2000. They are on the verge of

bankruptcy.

• The Cal PX ceased to operate its two markets on January 31, 2001.

The Lessons

Overall Design of the Power Market

• A poorly designed power market will not operate properly, and

inadequate attempts or delays in correcting market distortions will spill

over into a serious financial crisis.

• The California power reform crisis offers many valuable lessons on

“what not to do” for reformers of power sectors, particularly for the

establishment and regulation of a mandatory, wholesale power market

based on spot pricing.

• The California experience indirectly provides important lessons for the

privatization and regulation of distribution enterprises and new market

65

entities in developing countries, even though privatization was not an

element of California’s reform.

• The California experience also provides a lesson about crisis

management: there is no way out that is quick, painless or cheap.

“Quick-fix” solutions to basic design flaws usually fail and may

aggravate the problems. Any real solutions will impose heavy costs on

stakeholders such as suppliers, consumers, shareholders, and

legislators.

3. Latin American Countries

Almost two decades after the beginning of the UK experiment in the power

sector reforms and privatization, many other countries have either adopted or

are adopting a model that promotes competition in the power market to

achieve economic efficiency and higher quality services, as well as lower

consumer prices for electricity.

A. Brazil

Brazil started its power sector reform in the mid nineties implementing

changes in the management, organization, ownership and decision-making of

its electricity sector. Privatization was one of the initial steps of the process

which aimed to attract private investments and create competition within the

industry. As these changes have taken place it was observed that public

interest activities related to energy efficiency and R&D undertaken in the past

by state-owned utilities also changed.

Nature of Electricity Reforms in Brazil

The restructuring process started in the country without a prior establishment

of a clear regulatory framework and at the same time the tradition of

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centralised planning ended. Centralised government planning previously

required that ELETROBRÁS, the state national holding electrical utility,

organised, planned, financed, built, and operated the entire electrical power

system. The 2015 Power Sector Plan (ELETROBRÁS 1994) was the last

edition of a periodically updated document that served in the past to focus

ELETROBRÁS’ resources and those of its subsidiaries. Now, however, the

Plan is only indicative of the course that overall system expansion may

follow, not a plan for which ELETROBRÁS is directly responsible for the

implementation. The new system is based on the premises that it should foster

competition where possible (generation and commercialisation of electricity)

and regulate where necessary (transmission and distribution – monopolies

with open access). The restructuring process started with de-verticalisation

and the privatisation of distributing utilities. By 2001 more than 80% of the

electricity sold in the country is done by privatised distributing companies.

This contrasts with the situation found in the generating side, which is still

dominated by state owned companies and only 30% of generating capacity is

done by private enterprises. The new system re-defined the role of the public

sector which is no longer the main financial agent, planner, but now

responsible for the indicative planning for generation and normative for

transmission and regulator.

Reforms included the creation of the National Energy Policy Council (NEPC)

which is designed to be the most important body to determine overall energy

policies that can shape the future development of the sector and its

commitments towards sustainability. However, although created in 1997,

NEPC only had its first meeting in year 2000, and has met only to decide on

specific actions since then. It has not set out a national energy policy that

should guide long term actions for the sector. NEPC is responsible for macro-

energy policies, including division of federal/state responsibilities. The

committee includes a wide range of ministries representatives and is chaired

by the Minister of Mines and Energy.

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In late December 1996 the Brazilian Congress passed a law creating the

Agência Nacional de Energia Elétrica (ANEEL). Until then all utilities being

privatized were regulated only by the terms of the contract at the time of the

sale of assets by the public utility. This new agency has been entrusted with

regulatory oversight of the restructured Brazilian electric industry. Initially

ANEEL relied on the structure of the previous DNAEE, or National

Department of Electric Energy, a now-extinct MME department, and started

to function only in December 1997. ANEEL is responsible for setting up the

regulatory regime necessary to provide the right signals to the market and

other measures in accordance with national energy policies that should be

promulgated by NEPC. ANEEL regulates the power sector, sets guidelines for

tariffs and rate-making, approves tariffs, and has the authority to grant

concessions to service providers.

Such an authority resembles a licensing or authorization power to grant a

private agent the right to use public resources to generate, transmit, or

distribute power. ANEEL is also charged with establishing competition

among the actors, as well as reliability and cost effectiveness of service,

including to rural areas. ANEEL has decentralized its activities, transferring

regulation oversight to some State Public Utility Commissions that are better

positioned to monitor the performance of distribution utilities. Power sector

reforms also included the creation of a National System Operator (ONS) and a

wholesale electricity market (MAE).

After six years of the first privatised utility Brazil faced a severe electricity

shortage and had to implement a rationing plan during June /2001-

February/2002 (Table 1). This crisis resulted largely due to the absence of

national energy planning and energy policy guidelines that should shape clear

regulation which are needed for private investors to assess their risks and

returns on investments. The end result was the lack of investments in

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generation and transmission lines that have not come in the expected speed

and amount.

Table 14: Electricity Consumption in Brazil Twh (1994 – 2002)

Source: Electrobas (2003)

Lessons learned

It is very unlikely that initiatives in energy efficiency and R&D would have

taken place without the regulators’ enforcement in 1998 and later with the

implementation of Bill 9.991/00 by the National Congress. Power sector

reforms in Brazil provided the opportunity to enhance support and in fact

increase significantly the level of funding in these areas. However, provisions

in legislation alone are not sufficient condition to ensure that resources are

being used efficiently to maximize the public interest of energy-related

services. Analysing the country’s experience since 1998, it was observer an

important learning process within the regulator and also amongst the utilities.

Some utilities are perceiving the strategic importance of pursuing activities in

R&D, such as the technical improvement of their own staff, some small

companies are appearing as results of some more successful projects and a

better relationship between research centres and universities is being

developed (ABRADEE, 2003). This is a significant change in the relationship

with utilities and research establishments in the country. It also helped to

promote interesting spill over effects inducing the creating of new businesses

represented by small consulting firms and ESCOs. The experience with the

SECTOR 1994 1995 1996 1997 1998 1999 2000 2001 2002

Residential 55.957 63.579 68.581 74.089 79.340 81.249 83.494 73.770 72.660

Industrial 116.759 111.632 117.128 121.717 121.979 123.550 131.195 122.629 127.69

Commercial 28.885 32.277 34.388 38.198 41.544 43.562 47.437 44.517 45.256

Other 34.026 35.598 37.234 39.276 41.659 42.739 44.621 42.882 44.924

Total

236.627 243.096 257.331 273.280 284.522 291.110 306.747 283.798 290.529

69

public benefit fund CTEnerg is more recent. However it is illustrative that it

has invested much less than the amounts invested under the regulated utilities

efficiency and R&D programmes. The federal government has limited annual

spending in order to comply with macro-economic targets for public spending

and CTEnerg has been affected by these types of interventions.

The management of this fund is done by representatives from government,

academia and private sector, and this has been a novelty in the administration

of public funds in Brazil, and has contributed for a better screening of

investment options, during the period 2001-2002. This model, however, needs

yet to be consolidated and CTEnerg has to demonstrate a higher degree of

consistency and predictability over time. Interesting enough, legislation gives

conditions for a more stable operation, but indigenous institutions have not

been able to implement these conditions.

The provisions to ensure funding support for energy-efficiency and energy

R&D had an important impact for the institutional learning both in the public

sector and utilities.

B. Argentina

Restructuring of electricity industry began in 1992, prior to which the

electricity industry in Argentina suffered from lack of investment, resulting in

low availability of generation capacity; widening gap between demand &

supply; poor tariff policies; dependence on government for financial support;

frequent power interruptions; non-paying customers; illegal connections;

increase in technical and non-technical losses; overstaffing; a demotivated

work force; inefficiency and poor consumer service. The electricity industry

conditions were very much similar to the general conditions prevailing in

India. By the time of reform the system had deteriorated badly and was

characterised by considerable operational and financial problems. The cost of

electricity was high (around $60 per MWh), there were large commercial

70

losses due to theft and non-payment and periodic threats of blackouts,

aggravated in times of low rainfall by a large dependence on power from

hydroelectric stations.

NATURE OF ELECTRICITY REFORM IN ARGENTINA

The goal of the reform process was to have an electricity industry that was

capable of ensuring sufficient energy to the economy at the best price which

reflected the economic costs of maintaining and expanding the activity. It was

also driven by the increasing inability of the government to service the public

debt and the need to attract private investment into the sector.

In January 1992, the electricity privatisation law was passed. The reform was

based on the principle of open access to the wholesale capacity, energy pool

for generating facility & least cost dispatch. A national regulatory body,

ENRE (Ente Nacional Regulador de la Electricidad) and a national wholesale

market for electricity (CAMMESA) were established. Transmission and

dispatch were mandatorily separated from generation and distribution and no

generator was allowed to control more than 10% of the system’s capacity.

Three federal companies1, SEGBA, AYEE and HIDRONOR were

restructured by separating their generation, transmission and distribution

activities Companies to be privatised were sold through auction, using a two-

envelope process. This included a qualifying technical offer and a competitive

financial offer. Usually, at least a bare majority (51%) was offered for sale,

and sometimes much more. For example, 98% of a 448 MW hydroelectric

plant was sold to a domestic aluminium company, retaining 2% for the

employees2. In transmission and distribution, long-term concessions were

awarded. The first of SEGBA’s generators was sold in April 1992, followed

by two more in May and August. Two distribution companies were sold in

September, followed shortly by the high-voltage transmission company. The

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success of the privatisation depended to a great extent on the regulatory and

commercial environment as determined by ENRE and CAMMESA.

Demand and supply determine energy prices. The supply side of the

wholesale market is composed of independent power producers, privatised

generators, publicly owned generators, and imported electricity. The demand

side of the market is made up of private and public distribution companies,

large users (currently more than 100kWh annually) and foreign consumers.

There are three main types of prices: contractual, seasonal and spot.

Transmission and distribution prices (for supplies through distribution

companies) are regulated.

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 third parties. The price caps are reset every five years; in the interim,

the regulated company can avail of the benefits of cost reduction. Large users

can however, choose to be supplied directly by the generators or buy directly

in the spot market, instead of through the distribution company. The number

of large users in the wholesale market has risen rapidly. As distribution

companies must supply to large users at the same rate they charge other

customers, this helps to keep prices under control. While all federal

distribution assets have been privatised, many provincial distribution

companies remain in the public sector.

Effect of reforms

1. Low prices & higher reliability- Following the reform process, electricity

prices fell sharply. After a period of turbulence, they stabilised at around half

the pre privatisation levels (See Figure 4). The extent of outages also reduced

considerably (See Figure 5). In EDENOR’s distribution areas, outages fell

from over 20 hours to around 5 hours a year. Generators were fitted with

72

power system stabilisers, which permitted minimal disconnection of

generating capacity while addressing transmission faults.

2. Increased Efficiency- Electricity loss for non-technical reasons, such as

faulty billing and theft came down and generation availability increased

considerably. For example, the La Plata distribution company increased its

customer base by over 20%. Similarly, the availability of Costanera, a

generator near Buenos Aires went up from 30% to 75%.

3. Increased Investment- Substantial investments were also made in

upgrading the assets bought from the government. EDENOR, for instance,

made capital investments of $380 million over 1992 to 1995, and plans an

additional $500 million until the year 2000. It is anticipated that the total

investment in the electricity sector by 2000 will be around $ 7 billion.

Conclusion

The Argentine experience demonstrates that it is possible to effect measurable

changes in a state-owned electricity sector suffering from lack of funds and

inefficient management, within a reasonably short time frame. A number of

problems that plagued Argentina, such as high distribution losses, low

generator availability are similar to what India faces today. The Argentine

power system is much smaller, and has a better hydro thermal mix when

compared to Indian power system as a whole, but it may prove profitable to

examine the Argentine experience to see whether it would help with the

design of reform in India.

Indian States’ Experiences

The majority of states in India have started the reforms process, mostly in the last

few years. Even before official reforms, Karnataka had the first semi-unbundled

power sector in the country, with a separate PSU in charge of generation,

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Karnataka Power Company Limited (KPC), established in 1970. However, there

was still some capacity with the SEB, and true unbundling didn’t begin in India

until 1995-96, with Orissa’s reforms. Even Orissa had a PSU for generating

thermal capacity, but this was not considered an unbundled sector, with some

capacity remaining with the Orissa SEB. We present below some details on the

restructuring of various states, focusing on Orissa, Andhra Pradesh, Maharashtra

and New Delhi.

Orissa was not only a forerunner, but its reforms were under the aegis of the World

Bank. Andhra Pradesh has also been ahead in reforms, and has received extensive

World Bank funding for its reforms. Delhi, the capital, was unique in that its

utility had extremely high losses (40+ %), despite virtually no agriculture. This

very recently underwent full reforms with privatization of distribution, only the

second in India after Orissa. There are indications that Delhi’s reforms incorporate

lessons learned from the mistakes of Orissa.

Modes of Reform

While Orissa’s reform done with privatization, most of the subsequent states,

up until Delhi in 2002, reformed with corporatisation (unbundling) of the

SEBs across segments. Even when different distribution companies were set

up, these were on a geographic basis, 57 with no competition for retail

customers. Given the nature of the industry, institutionally there are no

structural barriers to competition in the generation sector. GENCOs already

share the market with Central PSUs and IPPs (it is a different matter that the

dispatch norms and tariff agreements don’t lead to real competition).

India appears to be relying on the single buyer model for now (making the

role of TRANSCO special – monopoly seller to DISTCOs, and monopsony

buyer from the GENCOs). While there is recognition of the pros and cons of a

single-buyer model, the government hopes this is a transitional solution,

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leading to open access to the wires (Deepak Parekh Expert Committee on

State Specific Reforms 2002). Instead of the transmission companies,

privatizing the handful of DISCOMs per state appears to be the thrust of the

government. However, a large number of options were considered by the

government, as indicated in Figure 7.

Financing and Past Debt

After the March 2001 Chief Minister’s conference, there was a consensus to

find a solution to the outstanding SEB dues (to PSUs), then about 41 thousand

crore Rupees (of which interest/surcharge was almost 16 thousand crore).

Under the Chairmanship of Montek Singh Ahluwalia, former Finance

Secretary, the Expert Group on Settlement of SEB Dues submitted its report

in May 2001. The aim was to come up with a one-time settlement scheme to

ensure timely payments in future. The report suggests reducing the surcharges

by 50%, and securitizing the remaining dues through the issuance of bonds by

the Reserve Bank of India (RBI). If the SEBs fails to pay for their fuel/power

in the future, this would impact their central assistance and access to coal

supplies. The report also recommended incentivizing states to undergo

reforms (Ahluwalia 2001), including establishing State Electricity Regulatory

Commissions, and metering distribution transformers. It is important to

recognize, as indicated in the Report, that the main challenge is the ongoing

(future) financial viability of the power sector, and clearing off the debts will

not solve that. SEBs complains that their finances consist largely of loans, and

conversion to equity would improve their finances significantly. However, it

remains unclear how much such a one-time solution would cater to solvency

improvement, instead of mere liquidity improvement, that is, unless, their

debt be wiped off, and the equity is allowed to operate with no minimum

returns requirement? In such a case, the State balance sheets would take a hit.

Overall, states find it easier to access funds after undergoing reforms,

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especially corporatization. These entities can access state, central government,

and even international (multi-lateral agency) funding.

Reforms in Andhra Pradesh

Andhra Pradesh has made phenomenal progress in the development of Power

sector since Independence. Andhra Pradesh State Electricity Board (APSEB)

established in April 1959 was responsible for overall growth of Power

generation, transmission and distribution in the entire state like any other

SEB. The state had 7,236 MW of installed generating capacity, third highest

among all the states in the country only after Maharashtra and Gujarat in

that order. It included 5,976 MW of state-owned generation 919 MW IPPs

and 1,000 MW from NTPC. It has electrified most of the villages in the state.

APSEB’s generation stations had been operating at high levels of PLF and

other performance efficiencies and the power stations have been rated among

the best performing power stations in the country.

In spite of the overall impressive growth, the growth in installed capacity

could not keep pace with the demand from various categories of customers

and therefore shortages; both energy and peaking have been experienced in

the system resulting in power cuts. Energy shortages increased from about 6.7

per cent in 1991-92 to about 22.1 per cent in 1996-97 and peak shortage had

reached from almost 15.8 per cent in 1991-92 to 23.6 per cent in 1996-97,

from a situation of helping neighbouring states in mid eighties. The

investments in transmission and distribution system have also not kept pace

with the demand for power. The transmission and distribution system was

beset with problems of high T & D losses, poor voltages, interruptions and

low reliability due to overload and shortages of power. Consequently,

customer service has also deteriorated considerably.

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The overall financial position of APSEB deteriorated and the SEB started

incurring losses, which resulted in greater dependence on the state

government. The accumulated losses of APSEB as on Mar 31, 1998 were

estimated to be Rs. 41 billion (excluding subsidy from the state government).

The poor financial viability came in the way of APSEB’s ability to further

develop the power sector.

Since 1995, it has been governed by the techno-savvy Chief Minister,

Chandrababu Naidu, a central figure in the reforms process. The state’s

policies have been progressive, and it is considered a success in terms of IT,

but its human development indices are generally below the national average.

A closer look indicates that much of the success has been in the cities, and the

benefits of plans have not trickled down to the villages. Naidu has been

successful in pushing reforms, no matter how unpopular, such as reducing

food subsidies. However, perhaps with an eye towards upcoming (2004)

elections but also driven by his push towards rural empowerment, Naidu

announced in August 2002 that the state should be power surplus, and that

agricultural power supply would be guaranteed at 9 hours per day, a big

improvement over then supply.

But this lofty promise made them a political target, and power sector reform

promises to be one of the largest election issues in the state. As mentioned

before, protests against tariff hikes in 2000 turned violent, but the AP

government still vowed to proceed with reforms. When considering the

success of AP’s reforms, political will is possibly the most important factor,

coupled with the efforts of management at the utilities. The key has been not

only efforts at policy, but execution.

In looking at the reforms, the first step was likely the 1995 high level

committee, chaired by Hiten Bhaya, to suggest reforms to be introduced in

the power sector (Reddy 2000). While focusing on unbundling APSEB and

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operating on commercial lines, as well as tariff rationalization, the World

Bank commented that the Hiten Bhaya Report didn’t go far enough with the

reforms process. The regulatory commission should focus on all tariffs, and

full unbundling, without holding companies, should be the way forward. The

World Bank also advocated a minimum 50 ps/kWh for agriculture. While the

AP government stated the WB role was only advisory, studying the reform

paper showed nearly full correlation with such recommendations (Reddy

2000). Driving ahead with reforms, the government pushed the Andhra

Pradesh Electricity Reforms Act of 1998 through with stunning speed. The

Telugu Desam Party government introduced the Bill on April 27, 1998, which

was passed within one day. Helping ensure its smooth passage, the entire

opposition was suspended from the Assembly (Reddy 2000).

Because of its reform programs, AP was the beneficiary of the major portion

of World Bank funding in India, and it received 6,600 crore of loans towards

total reforms, two-thirds of which were for the Andhra Pradesh Power Sector

Restructuring Program. These loans were under the Adaptable Program Loan

(APL). Such disbursements were despite sanctions imposed on India after its

May 1998 nuclear tests.

Implementation of Reforms

The functions of APSEB were segregated into generation, transmission and

distribution companies, each under a separate company. The existing

generating stations and those under construction were also transferred to a

state owned generation company, called APGENCO, which is also mandated

to set up on its own or jointly with private sector new thermal or hydro or

other power stations. A single buyer model was put in place under which

APGENCO would sell power to APTRANSCO, which in turn would sell to

the various distribution companies. Both companies have become effective

from 1st. February, 1999. The assets, liabilities and personnel were allocated

to these companies with effect from 31st. March 2000. The unbundling of the

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sector was primarily aimed to increase operational efficiencies and to allow

these entities to function independently and put them in decision taking mode.

More than 90% of the employees were allotted to the company of their

choice. The new power generation projects would be mainly developed by the

Independent Power Producers (IPPs) selected through International

Competitive Bidding (ICB) and joint venture companies of APGENCO with

private parties, other states or central undertakings.

Power Transmission

The power transmission network from 132KV and above including O&M of

interstate tie lines in the state, have been entrusted to APTRANSCO. It is

responsible for purchase of power from all purchasing sources under a

competitive and transparent power purchase process and dispatch power on

merit order basis, so as to avail the least cost power available in the grid. The

pooled power is being supplied to the different distribution companies. It is

also responsible for grid operations. The private sector may also be allowed in

developing power transmission networks, in future, keeping in view the

national policy.

Power Distribution

Initially the distribution function was with APTRANCO, and subsequently

the state was geographically divided to East, South, Central and South power

distribution companies. The borders for the 4 DISTCOs were chosen not on

operational rounds, but to ensure that no one company had an extreme mix of

consumers (too many agricultural or all the paying, i.e.,

industrial/commercial, customers). All the distribution companies are working

under separate licences granted by APERC. In order to involve the employees

in the reform process, the government of Andhra Pradesh proposed to invite

the employees to participate in the equity of new companies. The state

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government and the new companies signed corporatization Agreements to

specify the role, rights and obligations of the state government as owner and

give managerial, operational and financial autonomy to the companies to

perform.

Regulations of the Power Sector

The Government of Andhra Pradesh has established the Andhra Pradesh

Electricity Regulatory Commission (APERC), which has started functioning

from 3rd. April 1999. The objectives of the APERC are to regulate the power

sector, promote transparency, efficiency and economy in the operation and

management of the power utilities, encourage competition and help Andhra

Pradesh to attract private investment for development while ensuring fair

tariffs to the customers.

Restructuring and Private Participation

The distribution companies buy bulk power through APTRANSCO initially

and subsequently, these will be able to purchase directly from the generation

companies with the APTRANSCO only wheeling such power.

Andhra Pradesh has followed the Orissa model. It is expected that the

progress would be rapid as compared to Orissa as the state had demonstrated

strong political will to improve the infrastructure and to attract private

investment in to various sectors of the economy.

Business Plan

While approving the original plan, the state government has agreed to provide

financial assistance to the sector during the transition period till the sector

achieves a turn around and ceases to be a burden on state government

finances.

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Demand Side Management (DSM)

The power sector reforms will also tackle issues such as energy efficiency and

demand side management to improve efficiency in supply and end-use of

electricity, introduction of tariff linked DSM; time-of-day tariffs for certain

categories of customers to flatten load curve and to meet the peak demand,

improvement of efficiency of agriculture pumps, installation of capacitors and

installation of meters on all unmetered supplies and conservation of energy

with incentives and disincentives. Awareness campaigns will be launched to

promote energy conservation. All resources of energy will be encouraged and

various options to bring in demand-side-management measures will be

explored.

Funds Flow in Support of Reforms

Since announcement of Government policy to take up the reforms and

restructuring of the power sector and also various measures initiated by the

state government in pursuit of reforms, both national and international

funding agencies have come forward to support the reform programme and

Andhra Pradesh has been the biggest beneficiary of funds. The details of

some of the projects sanctioned / under consideration are:

• The World Bank agreed to lend, up to $1000 million for

transmission and distribution improvements and augmentation of

system over a decade. This would be given as a series of loans

under their Adaptable Program of Loans (APL). The first loan of

$210 million is already being used.

• Department for International Development (DFID) sanctioned

$42.7 million as a grant to revamp the distribution system. DFID is

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also providing $2.7 million as technical assistance grant to the

power sector.

• The Overseas Economic Cooperation Fund (OECF) now known as

JBIC sanctioned funds to the extent of Rs. 390 crores for Srisailam

Power evacuation scheme and Rs. 311 crores towards the Simhadri

power evacuation scheme.

• PFC is extending support to the tune of Rs. 275 crores out of which

Rs. 113 crores towards counterpart funding for the projects funded

by World Bank and OECF. PFC also sanctioned a loan of Rs. 240

crores for transmission and distribution schemes.

• Rural electrification corporation (REC) sanctioned Rs. 720 crores

for the period from 1998-2001 for APTRANSCO for rural

electrification works, in addition to rescheduling outstanding loans.

• Technical assistance extended through grants by DFID and CIDA

for implementation of Reforms and restructuring program.

Regulatory Support to Reforms

The APERC is considered independent, and has a retired Civil Servant as its

Chairman, a tax official as its member and former APSEB officers. It has a

strength of 60 staff members (high for SERCs in India), and has issued some

unique pronouncements in terms of power. They have published a “cost to

serve” model, whereby the different classes of consumers have different costs

explicitly calculated on economic grounds. They have also issued an order to

the utilities to meter all consumers within 3 years. The APERC tariff orders

have been challenged in the courts, but the Tariff Order for 2000-01 was

upheld in the Supreme Court in March 2002. Many more cases were ongoing

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in the Supreme Court (6 cases) and the High Court (nearly 100 cases) in 2001

(Prayas 2001).

APERC Tariff order 2002-2003: an Analysis

This is the third tariff order promulgated by APERC, and follows the model

whereby tariffs are determined by the APERC, and utilities must follow the

pricing models. An Annual Revenue Requirement (ARR) analysis leads to the

costs that each utility would face, and any shortfall from the revenues must be

borne by the State. APERC allowed explicit subsidy by the state, which had

to be paid to the DISTCOs. APERC announced Bulk Supply Tariffs (BST)

that the Transco would charge the DISTCOs (aka Discom). In arriving at its

calculations, APERC invited petitions and presentations from various parties,

not only the utilities and the State, but also consumers. Notable among the

challenges to submitted information were the transmission losses claimed by

APTRANSCO, and the amount of consumption by agriculture (submitted by

the DISTCOs). As per APERC, “The tariff design was further rationalized to

achieve the objectives set forth in the Reform Act of 1998. Attention was on

i) rationalization of categories; ii) rationalization of tariffs and iii) incentives

for incremental consumption by HT consumers.”

The tariff order modified the slabs as well as the tariffs for many consumers,

and introduced an optional metered tariff for agriculture. Any takers-up could

find lower tariffs than the flat-rate tariff, assuming low to normal

consumption. There were also incentives to consumer more electricity for

bulk consumers (industry), with rebates given for higher usage.

Efficiency Improvement Initiatives in A.P

Several initiatives have been taken to improve operational and financial

performance of the companies and notable among them are

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Enactment of “Anti Pilferage Legislation” in July 2000 providing for

very stiff penalty including mandatory imprisonment for a minimum

period of 3 months and a maximum of 5 years in addition to a penalty

varying from Rs. 5,000 to Rs. 50,000. The Act also provides for

denying electricity supply for 2 years to the premises where the offense

is committed and proved. Special Courts have been set up for speedy

trial of these offences. The tempo of inspections is being maintained

and all out efforts are being made to curb the menace of theft of energy

in the state. Consumer Analysis Tool (CAT) facilitates organizing raids

for detection of pilferage of energy. This has also helped in bringing

down the T&D losses. The T&D losses have come down from 38 per

cent in 1998-99 to 24.8 per cent in 2002-03 which was possible due to

introduction of metering at all interface points coupled with

enforcement of the Anti Theft Act.

Andhra Pradesh has taken up full-fledged energy auditing of 114 towns

and the T&D loss levels in these towns have been brought down to

less than 10 per cent.

The utilities have provided tamper-proof high accuracy meters for high

value services and installed 21,000 energy meters on low voltage side

of transformers exclusively feeding agricultural consumption in the

state. A massive metering plan is being implemented in the state, 2.8

million energy meters are already installed. The programme envisaged

fixing of HT & LT electronic meters on industrial services and

providing one lakh LT 3 Phase electronic meters on High Value

services and three lakhs single phase electronic meters for replacing

defective meters. The utilities have also provided exclusive express

feeders to high revenue yielding industrial services by bifurcating 702

existing mixed feeders in an effort to improve the reliability of supply

to industrial consumers which would result in better revenue.

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The introduction of electronic spot billing system in all the towns using

a handheld computer has facilitated the issue of bills on the spot, which

has facilitated the issue of bills on the spot, which has also reduced the

number of complaints relating to the wrong meter reading, wrong

billing etc.

The Transformer Information Monitoring System (TIMS) has helped

tracking failures and repair of distribution transformers and helped the

inventory management of distribution transformers. The “Supervisory

Control and Data Acquisition System” (SCADA) for operation and

control of 106 sub-stations in greater Hyderabad has facilitated

capturing data on real time basis and unmanned sub-stations.

Information Technology Initiatives

Many IT initiatives have been taken up to improve the quality of information,

maximize revenue, monitor operational performance and facilitate improved

customer service. A WEB based MIS system is in operation for conducting

detailed reviews at various levels. Similarly, a total consumer database has

been established which is being used not only for consumer service but also

for identifying cases of potential commercial losses. An information system

plan which is a road map for all IT related initiatives has been prepared for

the sector.

These efforts have helped in bringing down T&D losses from 38 per cent to

24.8 per cent i.e. a ten per cent reduction within 03 years. The revenues have

increased from Rs. 4,484 cr. To Rs. 7,238 cr. (2002-03) in the last 03 years

period, especially against revenue demand of Rs. 6,434 cr. The percentage of

collection of revenue has increased substantially. Realisation of cost per unit

has increased from 57 per cent to 82.5 per cent. Percentage of transformer

failures has come down from 28 per cent to 18 per cent. This has been

possible due to introduction of technology to reduce human intervention.

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CRISIL Rated Andhra Pradesh as the Best Utility in Implementing

Reforms

The power sector in Andhra Pradesh has been making steady progress in

achieving its cherished objectives while adopting the reform path. There is,

undoubtedly, a significant improvement in technical, financial and

commercial operations of the companies. Significant improvements are also

seen in metering, billing, revenue collection and reduction of losses especially

through the control of theft energy by implementing stringent punitive

measures. There has been marked improvement in consumer related services.

Several states are evincing keen interest in the progress made by A.P power

sector.

The CRISIL and ICRA have undertaken the performance analysis of all the

SEBs across the country to assess the commitment of the state governments

for reforms, performance of SERC’s and utilities. The state governments were

evaluated on their commitment on subsidy payments, outlook on tariff

reforms and enabling legislation, and operational support extended to the

utilities to tone up their functioning and implement the reform agenda. The

SERCs were evaluated on their tariff philosophy, efficiency norms,

implementation of tariff orders, while ensuring commercial operations and

protection of interest of consumers, utilities, investor and lenders. The utilities

were assessed on performance of generation and T&D related parameters. The

financial performance was measured on cost-revenue analysis, level of

receivables and liabilities.

Andhra Pradesh stood first among the states in three of the four sub-

parameters viz. payment of subsidy, and commitment for reforms, role of

SERC and the performance of successor utilities to SEB. However it occupied

third position after Karnataka and Maharashtra in respect of financial risk

86

analysis. It has however pointed out that further focus is needed to further

improve operational and commercial efficiency as well as improve customer

service. The utilities in A.P have planned several initiatives in operational,

commercial and consumer service, to show better results in the near future.

While there is no doubt about the existence of considerable scope for further

improving the technical, financial and commercial parameter, the A.P

experience demonstrated that improvement can be achieved by the utilities

given the will and the support by the government and the SERC, even without

privatization.

Future Course of Action

While the impressive performance of the power sector since initiation of

reforms is laudable, the government’s commitment for reforms, in spite of

considerable resistance, criticism and even demonstration by some opposition

political parties, is commendable. The state is however required to carry

forward the reforms further to get the fullest benefits to all the stake holders.

I. Need to Increase Domestic and Agricultural Tariffs

The government of Andhra Pradesh, however appears to be averse to

increase the tariffs in general and domestic and agricultural tariffs in

particular, keeping in view the opposition parties proposals to supply

power for agriculture consumption free of cost and the ensuing general

elections in 2004. However at the time of last general elections in

Andhra Pradesh, the electoral manifesto of a major political party

promised complete waiver of electricity arrears for the agriculturists

and also supply free power, if elected. The farming community

however did not bite this offer as is evident from the election results.

This outcome of the result reflects that farmers don’t expect free power

but wants quantitatively and qualitatively reliable power without

breakdowns, low voltages, etc. at a reasonable tariff, which is possible

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only by restructuring and reforming the power sector. While the farmer

certainly needs relief during the periods of drought as it is during 2003-

04, there should be gradual increase in tariffs to cover sizable portion

of cost of supply. It is therefore imperative that there’s a need to build

up consensus among the major national political parties on the need to

reform the electricity sector especially in respect of agricultural tariffs.

The state government should take the lead in building up such

consensus in the overall national interest.

II. State Governments Continued Support for Reforms Needed

It is often assumed that once the process of reforms and the associated

legal framework and various institutions are established, the

government has a limited role in the functioning of the electricity

sector. Indeed it is not so. The government’s support subsequently also

is indispensable to the successful completion of the reform process and

the sustainability of the sector in areas such as tariff reforms, subsidy

delivery, 100 per cent metering of the consumers and controlling theft

of energy.

III. Support for Tariff Reforms

With the introduction of regulatory regime, the task of rationalization

of existing tariff structure, the issues pertaining to efficiency

improvements, quality of supply and facilitating private investment

have entrusted to the regulators. The bedrock of the new tariff fixation

process is the involvement of the public through a transparent system

of public hearing and other forms of public consultation. This is a good

forum for sensitizing the general public about the problems being faced

by the utility and take stock of the utility’s performance as a public

utility, looking to the general interest of the public.

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It appears that the government owned utilities in Andhra Pradesh have

not been able to use this forum to present a true picture of the costs and

performance levels to improve their commercial viability. The tariff

proposals received from the utilities do not seem to reflect the

economic costs of the supply. The utilities have been optimistic in

forecasting higher percentages of sales to subsidizing categories of

industrial and commercial sectors than subsidized categories of

agricultural and domestic consumers with a view to preventing fixation

of realistic tariffs and making the regulator to enhance the tariffs,

though have not been projected by the utilities themselves to ensure

their financial viability.

It also appears that the licensees in AP have not been generally

demanding a 16 per cent rate of return in their revenue requirement. It

has been the regulators initiatives to provide for the same, again to

ensure long term viability of the utilities.

As the government ensures full cost recovery to the licensee by

providing subsidy transparently in the budget, the regulators role in the

final tariff determination has become limited, which causes hindrance

to the regulator to fix cost reflective retail tariffs by allowing the

government to exercise control indirectly over the regulators role in

determining viable and cost related tariff. There is need to taper off

subsidies over a period and the amount spent on subsidies could be

diverted to much neglect other sectors including social sectors.

IV. Agriculture Subsidy to Targeted Groups

In spite of regular and timely payment, including advance payment of

subsidy by the government during 2002-03, the licensees in AP are still

incurring huge financial losses due to excess purchase of power, which

goes to agriculture at a highly subsidized rate. In the current scheme of

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operations, the licensees’ supplies to agriculture are dictated by the

government rather than any financial or other guiding principle. It is

necessary to make realistic estimates about agriculture consumption

and encourage growing of less water intensive crops.

The other major issue is whether the current form of subsidy

administration is the most optimal one. The unrestricted supply to

agriculture at nominal fixed costs has resulted in cultivation of highly

water intensive crops in a surface irrigation deficit area, leading to

indiscriminate installation of tube wells and high capacity pumps in

order to grow crops like cotton. Besides the real gainers from such

measures are the financially well off farmers. There is a need to ensure

that it is the poor, marginal and below poverty line farmers who should

get benefits from the subsidy scheme and not the rich farmers. It is

therefore necessary for the government to ensure that the agriculture

subsidy is extended only to deserving target groups. A fool-proof

monitoring mechanism for subsidy mechanism has to be devised and

monitored.

V. Support for Efficiency Improvements

Andhra Pradesh is one of the few states that have allowed the strict

implementation of the Anti Theft Act, which allows the licensees

greater powers in detecting and controlling commercial losses

effectively. Necessary supports for enforcement of anti-theft measures

by the state government are required to be continued even after

privatization. However, the unmetered supply of nearly 25 per cent

power to the agriculture sector imposes restrictions on the effective use

of the Act. The APERC has directed all licensees to complete

agricultural by March 2003 and the licensees have fallen well short of

such directives. The regulators role is limited to directing the licensees

to address this problem through accurate metering of the interface

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points, regularization of the unauthorized consumers, metering of all

services, proper recovery of dues, etc. The commission is forced to go

in for alternatives like distribution transformer level metering to

estimate the quantum of agricultural consumption in the state which

does not give accurate picture about T & D losses.

VI. Timely Payment of Dues by Government Agencies

The central and state organizations, municipalities, local bodies, etc.

are some of the biggest defaulters in paying their bills. The government

should either ensure timely payment or the DISTCOs should be

allowed to disconnect as being done for other consumers. The state

Governments directive for prompt payment of dues failing which

power supply would be disconnected will go a long way.

VII. Need for Reduction of Subsidies

While the revenue gaps faced by the licensees have been stabilized

around Rs. 3,000 crores per year, they being Rs. 3,064 crore for 1999-

2000, Rs. 2,872 crore for 2000-01 and Rs. 2,942 crores for 2001-02

supported by subsidies by the Government, any such support is also

affected by other factors like additional support for debt repayment for

the licensees, Government of Andhra Pradesh support for capital

investment plans, electricity duty, water royalty, interstate power

purchase, guarantee commission, interest of repayment of Government

of Andhra Pradesh loans etc. The net input from Government for 2001-

02 is reduced to Rs. 2,378 crores which is a positive signal. It is also

noticed that the cross subsidy from other consumers to agricultural

consumers continue to be over a Rs. 1,000 crores or even more. The

Government of Andhra Pradesh still continues to pay substantial

amount towards power subsidy, thereby not allowing the tariffs to be

fixed on cost related basis which obviously deprives the other socio

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economic and infrastructure sectors their rightful claims. While the

cost of supply is steadily increasing year after year, the government

prefers to extend subsidies to the various segments, instead of bridging

the gap between cost of supply and average tariff.

VIII. Support for Privatization

The current electricity sector reform programme has not yet reached its

logical conclusion. The introduction of private entities and competition

for market is still to be attempted. Regarding APERC’s efforts towards

making the distribution domain investor-friendly, the APERC have

recently enunciated the draft for the Long Term Tariff Principles, the

first of its kind of document in India. These principles will help the

investor in determining his revenue requirements over a period and

result in tightening of efficiencies so as to ensure that the customers are

benefited over the long run. These will be crucial in the privatization

process in AP. The Government of Andhra Pradesh should go in for

privatization in joint sector mode at least in one or two distribution

companies, which would demonstrate to all the stake holders,

especially to the consumers the benefits of privatization. It is necessary

to fulfil certain prerequisites by the government before any private

investor would be willing to take on the distribution business. All these

measures are required to be undertaken expeditiously to take reform to

its logical conclusion.

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Reforms in Delhi Delhi, the state that includes the capital, New Delhi, used to have its power

supplied by the Delhi Vidyut Board (DVB). DVB, itself the reincarnation of

the Delhi Electric Supply Undertaking (DESU), was in the extreme position

of having very little generating assets, some 300 MW, relying on outside

(largely central) generators for its power (peak loads are over 3,000 MW).

Despite being an urban area, and hence, almost no agriculture, the theft

and losses were very high, estimated at 45+%.

While most other states underwent or are undergoing reforms in stages, Delhi

underwent reforms with a bang, though the initial reforms came under the

central government ERC Act of 1998, creating the Delhi ERC in 1999. The

Delhi Electricity Reform Ordinance was promulgated in October 2000 and

was replaced by the Delhi Electricity Reform Act, 2000. It’s worth noting that

the Delhi ERC is understaffed, in fact lacking 2 Commissioners (it only has

one Member, the Chairman). Subsequent reforms were undertaken in 2002,

when it unbundled its utility (into 3 zones) and privatized them at once (June

27, 2002).

Learning from the Orissa experience, the main metric for choosing companies

was not based on valuation, but on performance improvement goals. The

DISTCOs annual revenue requirements are calculated based on their

expenditure, performance (targets), and return on equity (16%). They pay the

Transco, a government company, a realistic lower amount, based on the

collection. Over time (5 years), this amount would match up to the full costs.

In the interim, the Transco will receive Rs, 3,250 crore as subsidy to cover its

costs to generators vis-à-vis the lower amount of money the DISTCOs would

be paying. One other feature is the retail tariffs are known to the DISTCOs in

advance, and were fixed by the ERC. The Delhi ERC also announced the total

losses in the 3 circles, averaging 50.7%!

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Details of the process of choosing the companies are given below, based on

the Distribution Policy Committee Report (Ministry of Power 2002) and

discussions with Government of India and DISTCOs officials.

• Valuation of assets: This will be based on “Business Valuation” Based

on reasonable assumptions of retail tariffs, efficiency improvements,

and expenses in the future, assets are valued such that the company can

become viable in a fixed period of time. The liabilities are also

considered this way, with some portion going to the successor

companies, some left with a holding company or refinanced, and some

covered through tariff increases.

• Mitigating uncertainty: Based on the annual revenue requirement

calculations and bulk supply tariff will be set such that the company

can make the required returns, assuming a performance target is met.

The difference in such a price and the cost to the TRANSCO will be

covered by the Delhi Government. Such support will effectively lower

the price for the DISTCOs, making them viable from day one.

• Criteria for selection of successful investor: A 5 year period, 2002-07

is the operating period for which bidders give their performance

improvement targets.

• Incentives for achieving higher efficiency gains: The benefits of

doing better than the targets will be equally shared between the

consumer and the DISTCOs, and underperformance will be borne

entirely by the DISTCOs.

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• Baseline data: The Bulk Supply Tariff Order has been released by the

Regulatory Commission in response to the filing by DVB before

bidding closed.

• Treatment of receivables: Past dues will be transferred to the Holding

Company. If these are recovered, 80% will go to the Holding

Company, and 20% to the DISTCOs.

The stated losses (subsidy requirement) for the 5 year period (covered by

support to the TRANSCO) will be Rs. 3, 250 crore. These are reported to be

in the form of a loan, under terms to be worked out subsequently. It would be

important to consider various exit strategies, in case the TRANSCO is unable

to repay the loan. In comparison, just before the reforms, from 2.4 million

customers, and 19 billion kWh of sales, an annual revenue of 5,400 crore was

required, with a gap of 1,100 crore rupees. The bidding processing revealed

the issue of limited players, as initial interest was shown only by 6 parties.

Only Tatas and BSES submitted final bids, and only BSES submitted bids for

all the 3 zones. Tatas won the North West Delhi Distribution Company, while

BSES took the South West and Central East Companies.

The main risks they face are that they either fail to meet the loss reduction

performance targets, or they fail to collect from consumers. They state the

government has been quite supportive, including by passing an anti-theft law,

making electricity theft a cognizable offense. It also gives them power to

disconnect non-paying users, even government users. While the DISTCOs

mention they worry about the accuracy of data, fearing Orissa-like effects, the

reverse is true from the consumer and system perspective. Without accurate

benchmarking, the DISTCOs might have an incentive to petition the ERC that

the initial losses are actually higher than they truly are.

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BSES states that labour is a non-trivial issue, as the workforce was handed

down as part of the privatization process. Nonetheless, they say the bigger

cost is infrastructure upgrading, to improve operations, metering, and

collection. Some of the recent ERC orders they must comply with are the

installation of electronic (solid state) meters, and metering on all the

distribution transformers.

Structure of the Unbundled DVB

The primary objective to unbundle the DVB was to create functionally

independent generation, transmission or distribution entities to have focused

attention on performance. This was also expected to result in a better

benchmarking of the performance of each activity and lead to an easier

identification of problem areas. The DVB has therefore been unbundled in to

GENCO Owns the generating stations of DVB

TRANSCO Owns the transmission network of DVB and also acts as a bulk

buyer from generating stations and the bulk supplier to the

DISCOMS

DISCOMS Separate distribution companies, which own the distribution,

network and are responsible for retail supply of electricity to the

consumers of Delhi.

Taking in to consideration the size of the distribution area for a metropolis

like Delhi and the load pattern, level of T & D losses, average billing losses

and number of unauthorized connections, it was decided to divide DVB in to

three DISCOMS. The other states which are in the process of unbundling the

SEBs have also divided the SEB into two or more viable distribution

companies.

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The Reform Process

Government of NCT of Delhi has ushered in a new era of privatization of

distribution on 1st. July, 2002 by unbundling Delhi Vidyut Board. This was a

major policy decision arrived after bringing out a white paper on power

situation and the problems facing power supply in Delhi in 1999. After

extensive consultations, the idea of reform including privatization of power

sector in Delhi emerged as credible alternative to improve the dismal

functioning of power sector in Delhi. The process of privatization of

distribution business of electricity was completed in record period of three

years.

Privatization of Distribution

In order to facilitate privatization, the government of Delhi issued the policy

direction in exercise of the powers conferred under section 12 of Delhi

Electricity Reform Act, 2000 on 22.11.2001 further amended on 31/05/02

incorporating that:

i. The Aggregate Technical and Commercial Losses (AT&C losses) shall

form the basis for determination of tariff and computation of incentives

for better performance. The measure of overall efficiency of

distribution business is based on AT&C losses which is the difference

between units input and units realized.

ii. The reduction in AT&C losses in next 5 years will be determined

through competitive bidding.

iii. 51 per cent equity shares shall be offered at face value to the winning

bidder.

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iv. The retail tariffs for three distribution licensees shall be identical till

the end of 2006-07.

v. Till the end of 2006-07, tariffs shall be determined in such a way that

the distribution licensees earn, at least 16 per cent return on the issued

and paid up capital and free reserves.

vi. The government of Delhi will make available to the TRANSCO, an

amount of Rs. 2,600 crores (Subsequently increased to Rs. 3,450 Cr) as

loan, to be repaid in 13 years with a moratorium of 3 years. The

transmission company will use the loan to bridge the gap between its

revenue requirements and the bulk supply price it may receive from the

DISCOMS.

Financial Restructuring

The financial restructuring was needed to ensure that the balance sheet of

DVB’s successor entities carried liabilities which were serviceable and

sustainable.

• Analysis of Liabilities

As the latest audited annual accounts of DVB were not available,

which was one of the significant failures of DVB for years, the balance

sheet of DVB for the year 1994-95 was considered as the base for

determination of the existing liabilities of DVB and most of the

information given by the DVB in the absence of audited figures, was

obviously highly provisional and the conclusions drawn on the basis of

such information were highly subjective and debatable. The increase or

decrease in the various liabilities from 1994-95 till the time of

privatization was, therefore, estimated based on the data furnished by

DVB.

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• Power and Fuel Purchase Liability

DVB has not been able to pay for its power and fuel purchase dues

from the Badarpur Power Station (BTPS) and central PSUs and all

such dues of DVB, prior to its constitution in February 1997 were left

with the Government. These dues could then be converted into long

term bonds thereby reducing the upfront cash burden on the

government.

• Loans from Government

The loans provided to DESU prior to the formation of DVB in 1997

and interests thereof were being considered as payable by the

government for the purposes of this restructuring exercise. The loans

were in perpetuity, in accordance with provisions of the electricity

supply Act and only 50 per cent of the principal payment carried an

effective interest rate of about 5.75 per cent to 6 per cent. In the

financial restructuring exercise, the loans became repayable over a

period of time, with a moratorium for a few years. The conversion of a

part of the Government loans in to equity was advisable as this

provided a reasonable debt equity ratio to the successor entities of

DVB.

• Funding of Initial Losses of DISCOMS

In the initial years, the DISCOMS would in all likelihood suffer losses,

inter alia, due to high T & D losses. The DVB was not the only SEB

which was incurring losses and all the SEBs in view of their poor

physical, financial and commercial operations are expected to incur

losses in the initial years after reforms are initiated. Unless these losses

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are funded by the Government, it will be difficult to attract private

sector in the distribution business. The methods which could be used

for funding losses are tariff increases, subsidy from the state

government, rising of debt funds from the market, deferred payments

due to TRANSCO and special debt liability in the opening balance

sheet. Even after considering reasonable tariff increases, the

DISCOMS are likely to incur losses as large increase in tariffs,

immediately after reforms, would create strong public resentment,

which needs to be avoided. It was also necessary to recognise, the

payment of large amount of subsidy would be a significant burden on

the finances of Government, which are none too satisfactory. The debt

funds would have only helped the DISCOMs in wiping out cash losses.

The deferred payment terms for payments due to TRANSCO has been

used by Orissa in privatization of distribution. However, to prevent

TRANSCO from defaulting on its own power purchase commitments

to the generation companies, the government had to infuse debt

funds into TRANSCO equal to the amount on which moratorium

was being allowed to the DISCOMS. Although the above structure

takes care of the cash losses, the losses in the profit and loss account

are not affected by this structure. Under special debt liability in the

opening balance sheet of the DISCOMS, debt funds were to be raised

from the financial markets backed by Government guarantee to take

care of cash losses. The losses in the profit and loss account were taken

care of by creating a special debt liability in favour of Government in

the opening balance sheet of the DISCOMS; this special debt liability

shall be written off in the first three years. This appears to be a

preferred option.

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• Unique Bidding Selection

One unique criterion in the power sector reforms in Delhi when

compared to Orissa was that of selection of the bidders for

privatization was done on the basis of reduction of total Aggregate

Technical and Commercial (AT&C) losses rather than valuation of

the shares in the distribution company on the basis of assets of the

distribution. The government had taken a conscious decision in this

regard because this happens to be the primary variable for successful

implementation of reforms and also sustaining this reform in the long

run. Since the core issue was the commercial efficiency, instead of

transmission and distribution losses only, the new concept of

aggregate technical and commercial was introduced. The former is

the energy supplied and the energy actually billed and this is subject to

errors because of erroneous and false billing. In Delhi Power Sector

Reforms, the concept of AT&C losses namely the difference of

energy supplied and energy, for which payment has actually been

recovered, was used. This figure will always be higher than the T & D

losses but will be more accurate pointer to the malady which the

privatization process intended to eradicate. It may be noted that Delhi

approach of taking AT&C loss, as the base for the purpose of

efficiency monitoring appears to be a step better than the usual

practice of taking the T&D losses, as was the case in Orissa.

• Bidding for AT&C Losses Reduction

Another unique feature in the Power Sector Reforms in Delhi is that

the loss reduction targets were established through competitive

bidding. The bidders were required to bid on the basis of year wise

reduction of AT&C losses over a period of 5 years and whichever

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bid gave the highest net present value became the highest bidder.

In order to encourage and motivate the bidders, it was also laid down

that successful bidder can retain 50 per cent of the additional revenue

recovered over and above the minimum target fixed by the government

and the balance 50 per cent of any excess efficiency gain shall be

passed on to the consumers. Since, the government holds the 49 per

cent of the equity of the companies, effectively only about 25 per cent

of the additional revenue will accrue to the private sector and 75 per

cent to the government and consumer.

In Delhi, efficiency improvement targets for five years have been set in

advance during the bidding process, which also gives legitimacy to the

targets and the private companies are fully aware of the improvements

required to be carried by them well in advance. The Government of

Delhi have given the regulatory policy directions whereby the regulator

will set the tariffs for five years based on the efficiency improvements

bid. In Orissa, the distribution companies did not know what the

regulator would decide next year on efficiency improvements. The

Delhi Government has given loan assistance to the TRANSCO to

keep the bulk supply tariff at a reasonable level and this was

basically done to avoid a tariff shock to the consumers. In Orissa,

the entire burden was borne by the consumers.

• Determination of Opening Loss Level

In order to facilitate the bidders to compete effectively, the DERC

after careful analysis of various factors like energy input,

distribution and billing loss and collection efficiency determined

50.7 per cent for all DISCOMs as opening levels of AT&C loss,

although there was variance among the DISCOMs. The Delhi

privatization was structured to avoid the mistakes made in Orissa

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reforms. It may be noted that Delhi approach of taking AT&C loss

as the base for efficiency monitoring, appears to be a better step

than the usual practice of taking the T&D losses which have not

been scientifically assessed. The investors were made to bid on the

loss reduction targets over the reopening losses determined by DERC

for first five years and on the efficiency, in sharp contrast to Orissa,

where the bidding was done on the value of the assets. During the

regulatory proceedings, the Government clarified that prior to the

bidding it shall stipulate the minimum loss reductions to be achieved

each year for the next five years, so as to make the sector self

sustaining within a period of five years. If the distribution company

achieves the loss reduction as per their bid, they would be able to

earn 16 per cent return on the issued and paid up capital and free

reserves till the end of 2006-07 subject to recovery of all expenses as

permitted by DERC. The incentive would be awarded only if the loss

reduction is higher than the level proposed by the investor.

LESSONS FROM ORISSA EXPERIENCE

It is obvious that some lessons are learnt from Orissa experience in

privatization. It is clear from Delhi privatization process that there was a

better recognition of the need for government support during the transition

period in the Delhi privatization which was totally absent in Orissa reforms.

1. Holding Company

The Delhi reforms have provided for creation of a Holding Company,

which will retain all the liabilities of DVB and also hold 49 per cent

share in the unbundled business, to facilitate the generation,

transmission and distribution companies to start with a clean balance

sheet, which is very essential to make reforms succeed.

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2. Baseline Data on Losses

The Orissa experience had highlighted the problem about lack of

realistic baseline data about one of the crucial factors of T&D losses.

In order to avoid any ambiguity about such data, Delhi adopted an

alternative approach of using AT&C (Aggregate Technical and

Commercial) losses, which is the difference between the unit inputs

and units realized (billed and collected) in which it has also included

the collection efficiency. The AT&C loss has formed the basis for

determination of tariffs and also for fixation of incentives for better

performance.

3. Balance Sheet Restructuring

In Delhi, a business valuation approach was adopted for valuing the

assets instead of revaluation of assets as in the case of Orissa to avoid

problems created due to over valuation of assets in terms of tariffs,

returns etc. The business value was arrived on the basis of future

earning potential assuming reasonable tariff increases and efficiency

improvements instead of on basis of depreciated replacement value. It

was assumed that the electricity business will become self sustaining

and will result in minimum tariff shock.

4. Bidding Process

There was a major difference in the criteria for bidder selection even

though Delhi also went through competitive bidding process. The

bidder was selected in Orissa on the basis of highest offer for

acquiring 51 per cent of the shares, the criteria for selection in Delhi

was based on maximum reduction in AT&C losses over a five year

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period and excess reduction, over the level mutually agreed, the

licensees would retain 50 per cent of the revenue thud recovered,

which would be shared between the joint venture partners and the

remaining 50 per cent shall be passed on to the consumers.

5. Government Support

The Government had withdrawn all subsidy support immediately after

privatization in Orissa, resulting in serious impact on DISCOMs and

there was also no clear data available about T&D losses in Orissa. In

order to overcome these problems, the Government of Delhi issued a

policy directive, containing the approach to loss reduction in five

years, retail tariff policy including returns on investments, subsidy

support etc. The loss reduction to be achieved over a five year

timeframe was specified in initial document itself to induce the bidder

to consider entry into business and AT&C losses reduction will be

transparently decided on the basis of competitive bidding and 51 per

cent equity shares shall be offered at face value. The AT&C loss will

be the basis for determination of tariffs and for computation of

incentives for better performance and the base level of AT&C losses

will be decided by the commission.

If actual AT&C loss reduction is less than the target for that year, the entire

shortfall in revenue because of the same shall be borne by the distribution

licensee. The tariffs till the end of 2006-07, subject to that all expenses shall

be permitted by the DERC, be determined in such a way that the distribution

licensees earn at least 16 per cent return on the issued and paid up capital and

free reserves subject to approval of SERC. The retail tariffs for the three

distribution licensees shall be identical till the end of 2006-07.

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The Government of NCT of Delhi will provide Rs. 3,450 crore as loan

(Initially Rs. 2,600 crores) during the transition period of five years to the

TRANSCO. The Government’s decision to provide a loan of Rs. 3,450 crores

to TRANSCO for five years, which would help to keep down the tariffs and

help the consumers, is an improvement over Orissa experiment. Similarly

incentives provided for better performance in respect of AT&C, is also a step

in the right direction.

The target of reduction in Aggregate Technical and Commercial (AT&C)

losses by 17.5 per cent in five years prima facie may appear to be very

lenient. However, after taking in to consideration the present magnitude of

losses and the failure of DVB to bring down the losses during the last several

years and these companies quoting for even lesser target than minimum

stipulation the Government of Delhi was left with no other option than to

agree for 17.5 per cent reduction.

Single Buyer Model

Another area of criticism has been the single buyer model adopted by Delhi,

which makes mandatory for all the DISCOMs to buy power through

TRANSCO and sell only through TRANSCO. It appears the present

arrangement of TRANSCO selling power to these companies is only an

interim arrangement and thereafter, the DISCOMs would have the

flexibility to buy power from anyone. While in the long run, it is desirable to

encourage competition among the buyers and sellers of power, presently this

arrangement would help these two companies to concentrate on

improvements in power distribution as both the companies will have their

hands full in managing the power distribution. The two private companies

would have to make special efforts to bring about improvements in customer

services, metering, billing, collection of revenue and control on theft.

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The state Government should continue to support the private companies, till

the operations are stabilized and by legislating anti-theft laws, which would

go a long way in curbing T&D losses.

The DISCOMs can anvil financial support under the Accelerated Power

Development and Reforms Programme. The government has not yet enacted

Anti Theft Act, which it is hoped would be done sooner than later.

Improvements will be slow but steady

Keeping in mind the precarious state of the power sector in Delhi, both

TATAs and BSES have formulated a multi-pronged strategy to battle tough

times ahead by conducting energy audits, audits at the distribution

transformer level, cutting down AT&C losses, enhancing reliability,

improving collections and fostering employee efficiency. The private

companies are having massive programmes to install new meters and replace

the old meters in a time bound programme, as they attach considerable

importance to these from commercial point of view. Both the companies have

stepped up anti-theft drive. To enhance revenue stream, the billing and

collection system have been streamlined. As on line computerized billing

system has been put in place. To improve system reliability, the distribution

system including HT and LT network are being augmented and strengthened

repairs, replacements and life extensions of equipment is being done.

Maintenance programmes are given prominence. Massive programme for

installation/repair of capacitors is undertaken to reduce the reactive power so

as to improve the voltage. The DISCOMs have also started outsourcing

critical commercial activities like consumer survey route sequencing, meter

reading, billing etc. Intensive training programme of employee has been

undertaken. The results of all these initiatives have started showing in the

increased operational efficiency, in reduction of AT&C losses, improvements

in the revenue collections, decline in failure of transformers. While it is too

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early to comment on the results of privatization, it is hoped that the overall

power situation will be better than what it had been during DVB period. It

needs to be realised that the problems of the power sector have been

accumulated over a period of 50 years. There are no easy solutions and instant

cure for Delhi’s growing power problems. The change of mindset, perception

and attitudes of the employees, bureaucracy, public, consumers, elected

representatives and the Government is an essential pre-requisite to make

privatization of power distribution a success. The successes of DISCOMs are

critical for the future application of the Delhi distribution model to other

states.

FUTURE COURSE OF ACTION

a) Need for Additional Generation Capacity

One of the major constraints faced in Delhi is its almost total dependence on

the generation from central units for its power supply, as its demand is far

more than the ramshackle power stations, within the capital, can cope with.

DVB has an installed capacity of 694 MW but normal generation is about 350

MW. Delhi’s power generation capacity has not been augmented. The thermal

plants are all of obsolete technology. Over-dependence on Northern grid has

also its limitations, due to competing demands on the system. The power from

all sources put together is always less than the demand at peak hours and the

problems get compounded during summer and winter, Delhi is forced to buy

power not only from Northern Grid but also from far flung areas. In contrast,

the relatively uninterrupted power supply in Mumbai is due to TATA and

BSES, who together have an installed capacity of 2,300 MW and which is

further supplemented by MSEB. This generation capacity is further

strengthened by 400 KV ring main sub-stations with islanding facilities, so

that whenever there are system disturbances either in MSEB grid and/or

western grid, Mumbai system isolates itself, as happened even on 1st of

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August 2002 thereby providing bare minimum power supply, at least, to run

the essential services like Railways, transport, health and water supply.

The DVB was undoubtedly India’s largest urban power utility. The peak

demand for power is already in the horizon of 5,500 MW and energy

requirement will be over 20 billion units and peak demand is growing almost

at 10 per cent a year. The per capita consumption of power is almost three

times higher than the all India average. While demand is galloping, hardly any

new generation capacity has been added in the recent times.

Delhi heading towards a major catastrophe unless adequate dedicated

generation capacity of about 1,500 MW to 2,000 MW to Delhi is created, not

only by putting up projects in other states like Himachal Pradesh but also

purchasing surplus power from eastern region on a long term contract basis. If

there are environmental constraints in setting up plants in Delhi, the dedicated

power projects could be set up in other states and the power could be wheeled

on the existing network. Over-dependence on Northern Grid can lead to

serious problems in the long run. Though this is a long term strategy, it is

essential to take immediate effective steps through the private sector to

augment its generation capacity. There are already some private sector

proposals which should be finalised without further delay.

b) Augmentation of Transmission

There is also a need to establish 400 KV ring mains by establishing a

number of sub-stations and EHV transmission network and also to create

islanding facilities and to increase power generation substantially, as the

system is presently working on the threshold. Even a small snag, snowballs

into a major crisis.

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The power crisis in Delhi is further compounded by the excessive dependence

on Northern Grid, as the constituent states themselves have not created

adequate generation capacity, leading to overdrawl beyond allocation and

have not taken adequate steps to maintain required voltage profile and also to

maintain grid discipline. This leaves no option to Delhi but to resort to

unscheduled load-shedding resulting in public outcry. In times of power

shortage in the region, Delhi also gets equally affected. In order to ensure

adequate availability and reliable supply to meet the growing demand for

power, it should be able to island itself in times of crisis in the Northern

Region and maintain un-interrupted supply of power at least to its essential

consumers such as Water Supply, Hospitals, and Railways, etc. Unless

generation and transmission capacity is augmented substantially, Delhi will

not realize completely the benefits of reforms in the sector and consumers will

continue to face blackouts, brown outs, load-shedding and shortages.

Conclusion

The Delhi privatization guarantees a 16 per cent return on equity, subject to

the licensees achieving their committed loss reduction target. These targets

were determined by a bidding process but, given the poor response, they were

finally determined by negotiations. The main implication of Delhi

privatization is that given the state of power sector, investors are unwilling to

take on any risk above the bare minimum, and the regulator is unwilling to

commit to any set of multi-year tariff principles. The government has

provided for a loan support of Rs. 3,450 crores since retail tariffs are not

expected to be adequate to enable the licensees to pay full cost of power and

also the 16 per cent return. However, since the regulator has not committed to

commit to the multi-year tariff principles, there is some uncertainty about

the full extent of the government exposure. In addition, there may be disputes

between the government and the licensee about the measurement of the true

level of AT&C losses and the licensees’ achievement of committed

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reductions. In fact the opening level of AT&C losses, as determined by the

regulator, is itself based on certain assumptions and projections. Similarly the

liabilities of the DVB were not based on up-to-dated audited reports and a

conclusion on the basis of such information is highly subjective. It is quite

likely that the budgeted amount of Rs. 3,450 crores as transition support may

not be adequate and the matter needs to be closely monitored and additional

provisions made whenever needed.

Another apprehension about the reforms is that given the problems in the

sector and the lack of reliable data, the contracts with private companies are

likely to be severely incomplete and unenforceable which may result in

serious legal problems. Perhaps the transition phase reforms needs to be

preceded by a ‘pre transition’ no privatization phase during which the State

Electricity Boards undertakes fundamental risk mitigating actions.

Meaningful privatization is possible only in case durable progress is made by

undertaking close to 100 per cent metering, billing and collection, proper

determination of assets and liabilities of the successor companies is done;

disconnections of illegal connections and progressive reduction in subsidies /

or cross subsides in tariffs.

The Government of Delhi deserves all the credit for improving on the

experience from Orissa reforms and showing the way to other reforming

states.

The Electricity Act 2003 (Act No. 36 of 2003) The Electricity Act 2003 (except section 121) has come in to force with effect

from 10th. June 2003 vide Notification No. SO.669 (E) dated 10th June 2003

issued by Ministry of Power, Govt. of India. The act aims to consolidate the

laws relating to generation, transmission, distribution trading and use of

electricity and generally for taking measures conducive to development of

Electricity industry, promoting competition therein, protecting interest of

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consumers and supply of electricity to all areas, rationalization of electricity

tariff, ensuring transparent policies regarding subsidies, promotion of efficient

and environment benign policies, constitution of central electricity authority,

regulatory commissions and establishment of Appellate Tribunal and for

matters connected therewith or incidental thereto.

The Act 2003 has repealed the Indian Electricity Act. 1910, Electricity Supply

Act 1948 and the Electricity Regulatory Commission Act 1998, but has saved

certain provisions of the Indian Electricity Act and Electricity Supply Act as

contained in Section 185 of the Electricity Act 2003. The Electricity Act 2003

provides that the provisions of the enactment specified in the schedule (which

include OER Act 1995) which are not inconsistent with the provisions of the

Electricity Act. 2003 shall apply to the states in which enactments are

applicable.

Key Features of the Electricity Act 2003

1. Central government shall prepare National Electricity Policy and Tariff

Policy in consultation with state govt.s and Central Electricity

Authority (CEA). CEA shall prepare National Electricity Plan in

accordance with the National Electricity Policy.

2. Generation of Electricity has been permitted without obtaining a

license provided it complies with the technical standards for

connectivity to GRID. Hydro generation shall need the approval of the

state govt. concerned and clearance of CEA.

3. Captive generation freely permitted and the scope widened. A captive

shall have the right to open access for carrying electricity from captive

generating plant to the destination for its use subject to availability of

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transmission facility. Captive power plant has been removed from the

ambit of license and other permissions.

4. Establishment of National Load Despatch Centre (NLDC) at the

national level for optimum scheduling of despatch of electricity among

regional load despatch centres. NLDC shall not engage in the business

of trading in Electricity and shall be operated by a Govt. Company or

any authority/corporation established under any central Act.

5. Regional Load Despatch Centre (RLDC) shall be operated by a

government company or any authority/corporation established under

central government act. The Central Transmission Utility (CTU) shall

operate the RLDC till such time it is operated by a Govt. Company etc.

6. The State Load Despatch Centre (SLDC) shall ensure integration

operation in the power sector in the state and shall be responsible for

optimum scheduling of despatch of electricity within the state. The

SLDC shall be operated by a Govt. Company or any

authority/corporation established under any state act. Till such time it

is operated by a govt. company etc. the State Transmission Utility

(STU) will operate the SLDC.

7. Transmission and Distribution of electricity and trading in electricity

shall require license from the appropriate commission.

8. Central transmission utility and state transmission utility at their

respective levels shall be responsible for planned and coordinated

development of transmission network.

9. The central transmission utility shall not engage in generation of

electricity or trading in electricity.

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10. Distribution License shall be free to undertake generation and

generating company would be free to take up distribution license.

11. For Rural Areas, stand alone systems for generation and distribution of

electricity shall be permitted without any license.

12. Appropriate Commission may grant license to two or more persons for

distribution of electricity within the same area.

13. Trading of Power is recognised as a distinctive activity with

Regulatory Commissions being authorized to fix ceilings and trading

margins, if necessary.

14. Central transmission utility and state transmission utility shall provide

the commission may specify non-discriminatory open access to its

transmission system on payment of transmission charges and a

surcharge as. The surcharge shall be utilised to meet the current level

of cross subsidy and shall be progressively reduced and eliminated.

15. The state commission shall introduce open access in phases and subject

to such conditions within one year. Such open access will be available

on payment of transmission charges and a surcharge and the surcharge

will be utilised to meet the current level of cross subsidy.

16. Transmission Licensee and distribution licensee have been permitted to

engage in any business for optimum utilization of its assets.

17. Tariff determination principles under the repealed laws/enactments

shall continue to apply for a period of one year or till the regulations

are framed under the Electricity Act 2003 whichever is earlier.

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18. Generation Tariff shall be subject to determination by the appropriate

commission.

19. Setting up of State Electricity Regulatory Commission is a mandatory

requirement.

20. Where state government requires grant of any subsidy to any consumer

or class of consumers, the amount to be compensated to the person

affected by the grant of subsidy. The subsidized tariff shall be

applicable on payment of the subsidy by the state government.

21. Metering of all electricity Supply have been made mandatory within

two years or within such extended period as may be allowed by the

commission to complete metering.

22. An Appellate Tribunal will be constituted to hear the appeals against

decision of SERCs & CERC.

23. Provisions relating to theft of Electricity have been made more

stringent. States will be required to set up Special courts to deal with

theft of electricity and line materials for speedy trial of offences.

24. Distribution Licenses permitted to undertake distribution of Electricity

in a specified area through franchisee where franchisee is not required

to have a license. The distribution license shall be responsible for

distribution of electricity in the said area of supply.

25. Distribution Licensees shall establish a forum for redressal of

grievances of the consumers. Any consumer aggrieved by non-

redressal of grievances may represent to an authority known as

Ombudsman to be appointed by the state commission.

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26. The act provides re-organisation of State Electricity Board with an

objective of corporatising the generation, transmission, distribution and

trading functions.

Implementation of Montek Singh Ahluwalia Report

In pursuance of one of the resolutions passed in the Chief Ministers’

Conference presided over by the Hon’ble Prime Minister on 03.03.2001, the

Government of India constituted an Expert Group under the Chairmanship of

Shri Montek Singh Ahluwalia, Member (Energy), and Planning Commission

to:

(a) Recommend measures for one time settlement of outstanding dues of

SEBs to CPSUs.

(b)Suggest a strategy for capital restructuring of SEBs including the

provision of structural adjustment of loans so as to enable them to tide over

present financial crisis and make them operationally viable.

The Expert Group has submitted its report to the Ministry of Power on Part

(a) above in May 2001. As per the report, as on 28.02.2001, the SEBs owed

about Rs. 41,473 Crore to various CPSUs and Railways. This amount

consisted of Rs. 25,727 crore of principal payment and Rs. 15,746 Crore by

way of surcharge / interest on delayed payments. The Group deliberated on

whether the settlement should be attempted independently or as a part of the

reform process. They however felt that although both are interlinked, it would

be prohibitively difficult for the SEBs to reform if they have to carry the huge

financial burden of outstanding dues. The Group therefore recommended that

this financial liability should be taken over by their States and the CPSUs

should also share this burden by waiving off part of their debt.

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The main features of proposed scheme for one time Settlement are:

• 50% of the surcharge/interest on delayed payments should be waived

for the participating States.

• Remaining 50% of the surcharge/interest and the full principal amount

have to be securitised through bonds issued by State Governments.

• The bonds should be issued through the RBI at a taxfree interest rate of

8.5% per annum with terms such that entire principal is repaid between

6th and 15th years and with lock-in restrictions allowing release of

only 10% bonds each year in secondary market.

• Timely payment of current dues and opening of LC equal to105% of

average monthly billing for preceding 12 months.

• SEBs should accept reform based performance milestones such as

setting up of SERCs, issuance and implementation of tariff orders,

energy audit at 11 kV feeders, metering of distribution feeders and

improvement in revenue realisation.

• Scheme to be effective only after half of the States with Annual Billing

of over Rs.500 crores from CPSUs give their consent.

Incentives

• If SEBs do not default on their current dues and adhere to performance

milestones, CPSUs should pay them biannual cash incentives equal to

2% of value of bonds for first 4 years starting 01.04.2001

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• If SEBs open and maintain LCs by Dec 2001, CPSUs should pay them

one time cash incentive equal to 2% of value of bonds.

Disincentives

• Graded reduction in supply of power/ coal from CPSUs for defaulters

on current payments.

• Where defaults exceed 90 days from the date of billing, GOI to recover

through adjustment against Central Plan Assistance and other

devolutions from the Centre.

• States withholding consent beyond 60 days of the scheme becoming

effective to be denied discretionary allocation as well as any assistance

under APDP.

The high level Empowered Group consisting of Chief Ministers, Deputy

Chairman, Planning Commission, Finance Minister and Power Minister,

which has been constituted to monitor and guide the reform process, has

approved the recommendations with the following modifications:

(a) Waiver of surcharge recommended by the Expert Group shall be increased

from 50 to 60%.

(b) Incentives for a period of 4 years @ 4% of the face value of the bonds for

achievement of performance milestones by the SEBs shall be increased to 6%

in the first year and 5% in the second year.

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Single Buyer vs. Multi Buyer Model in Distribution

The states such as Orissa (OPTCL), Andhra Pradesh (APTRANSCO),

Haryana (HVPNL), Rajasthan and Uttar Pradesh (UPPCL), who have

restructured the power industry, have adopted “Single Buyer Model”, wherein

the state transmission companies are the monopoly purchases of Power

and they sell power to distribution companies. The single buyer model has

a number of disadvantages, particularly in situations with low collection

efficiency and payment indiscipline.

Since generation companies (GENCOs) must sell their power to the

TRANSCO, the distribution companies can buy from the TRANSCO alone,

and the consumer also likewise has to buy from the same DISCOM. As all the

prices are determined on a ‘Cost Plus basis’ either through negotiation or by

the regulator, the consumer, etc.

World Bank Models on Structural Reforms in Power Sector

Ten distinct models of power structure reform can be found in the literature,

but most countries believe that four generic models are adequate to represent

the available structural options. These are shown in Figure 3. It should be

noted that these models should not be interpreted as rigid presentations of

reality but as a basis for conceptual analysis and discussion.

Model 1- This is an integrated monopoly with no competing generating or

distribution companies in an area. Customers buy from Monopoly

Company.

Model 2- Distribution is separated but generation, transmission remain

integrated. Distribution has no choice of supplier from whom to buy power.

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This is still a full monopoly model but it may be considered as a step

towards decentralization & eventual competition.

Model 3- In the purchasing agency model, competition to generate power

exists but all sales must be made to the designated purchasing agency. This

Agency then sells it to retailers or to its own customers, who have no choice

of supplier.

Model 4- This involves central transmission with open access for retail

sales. Competition exists in generation, with customers or retailers having a

choice of supplier, possibly buying and selling through the power pool.

The above models differ in a number of aspects. The degree of vertical

integration depends on the extent to which generation, transmission, and

distribution are managed together or separately. The relevant criterion for

restructuring decisions is the relative cost making contracts between separate

entities versus benefits of greater production efficiency through competition,

taking into account that small systems are not amenable to it. The degree of

concentration or fragmentation is defined by the number of enterprises

conducting the same activity within the same geographic or administrative

region. The size of the market would determine the advantages of horizontal

un-bundling. Typically, in large or federally organized countries, such as

India, China, or Brazil, a large number of local enterprises are operating. In a

small country, such as Georgia or Lithuania, excessive fragmentation would

add relatively large transaction costs.

The countries that the World Bank serves have adopted various models of

reform in their power sectors, each of which merits separate discussion and

analysis. The general conclusions from the World Bank's experience in sector

restructuring are as follows:

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o Generation is the first core power activity that can be separated and

made competitive. Decentralizing the sector by introducing additional

players such as IPPs is the first step toward making generation a

competitive activity.

o Successful implementation of structural reform requires both the

hardware of technological advances in the power system and the

software of workable contractual relationships.

o Separate distribution enterprises are encountered in many developing

countries and may indicate relatively easy transition to a more

unbundled and competitive system.

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Table 15: Comparative statement of sops extended by different countries

CHINA INDIA • 5-year tax holiday. • Half-rate tax for 5 more

years. • Equity return restricted to

12.5%.

• 5-year tax holiday. • Reduced duty for capital

equipment. • Equity return restricted to

16% (equity “sweeteners” keyed to plant load factor.

• Purchaser obligations guaranteed for initial “fast-track” projects.

PAKISTAN

PHILIPPINES

• No corporate tax; reduced dividend tax.

• Sales-tax and custom-duty relief for capital equipment.

• Government guarantee for fuel supply.

• Ceiling bulk-purchase price specified.

• Sales tax and customs-duty

relief for capital equipment. • Government guarantee of

purchaser obligations. • Government guarantee for

fuel supply.

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123

Electricity Tariff

This chapter traces the changes in the legal provisions governing electricity

power tariffs and discusses the processes and methodologies adopted over

time for tariff setting till the formulation under Section 178 of the Electricity

Act, 2003, which may be called the Central Electricity Regulatory

Commission (Terms and Conditions of Tariff) Regulations, 2004.

The legal provisions for the regulation of tariffs of power utilities can be

traced back to the Indian Electricity Act 1910 (IE Act). However in keeping

with the perceptions of the times there was no attempt at being prescriptive by

specifying either the principles or the methodology to be followed for tariff

setting enjoining that tariffs must be non-discriminatory and allow a

reasonable return to the licensee.

The first attempt to closely regulate monopolistic power utilities by defining

the basis on which tariffs could be charged was made in the Electricity Supply

Act. 1948(E(S) Act). At the time there were two types of entities in the power

sector: Licensees under the IE Act and state electricity boards (SEBs) created

by the E(S) Act.

Schedule VI of the E(S) Act prescribed the methodology to be followed for

the determination of the tariffs of power utilities which were Licensees under

the IE Act. This is a detailed cost plus methodology where the rate of return is

fixed. Electricity Regulatory Commissions Act. 1998 (ERC Act) was the

predecessor to the newly formed Central Electricity Regulatory Commission

(Terms and Conditions of Tariff) Regulations, 2004.

The Central Electricity Regulatory Commission hereby makes the following

regulations, namely:

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Short Title & Commencement

1. These regulations may be called the Central Electricity Regulatory

Commission (Terms and Conditions of Tariff) Regulations, 2004.

These regulations shall come into force on 1.4.2004, and unless

reviewed earlier or extended by the Commission, shall remain in force

for a period of 5 years.

Scope & Extent of Application

1. Where tariff has been determined through transparent process of

bidding in accordance with the guidelines issued by the Central

Government, the Commission shall adopt such tariff in accordance with

the provisions of the Act.

2. These regulations shall apply in all other cases where tariff is to be

determined by the Commission based on capital cost.

Norms of operation to be ceiling norms

1. For removal of doubts, it is clarified that the norms of operation

specified under these regulations are the ceiling norms and this shall

not preclude the generating company or the transmission licensee, as

the case may be, and the beneficiaries from agreeing to improved

norms of operation and in case the improved norms are agreed to, such

improved norms shall be applicable for determination of tariff.

Tariff determination

• Tariff in respect of a generating station under these regulations shall be

determined stage-wise, unit-wise or for the whole generating station

and tariff for the transmission system shall be determined line-wise,

sub-station-wise and system-wise, as the case may be, and aggregated

to regional tariff.

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• For the purpose of tariff, the capital cost of the project shall be broken

up into stages and by distinct units forming part of the project. Where

the stage-wise, unit-wise, line-wise or sub-station-wise break up of the

capital cost of the project is not available and in case of on-going

projects, the common facilities shall be apportioned on the basis of the

installed capacity of the units and lines or sub-stations. In relation to

multipurpose hydro electric projects, with irrigation, flood control and

power components, the capital cost chargeable to the power component

of the project only shall be considered for determination of tariff.

Explanation

For the purpose of this chapter, 'project' includes a generating station

and the transmission system.

Application for determination of tariff

• The generating company or the transmission licensee, as the case may

be, may make an application for fixation of tariff in respect of the

completed units of the generating station or the lines or sub-stations of

the transmission system.

• In case of the existing generating station or the existing transmission

system, the generating company or the transmission licensee, as the

case may be, shall make an application for determination of tariff as

per Appendix I to these regulations.

• In case of a generating station or the transmission system declared

under commercial operation on or after 1.4.2004, an application for

fixation of tariff shall be made in two stages, namely:

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1. A generating company or a transmission licensee may make an

application as per Appendix I to these regulations, for

determination of provisional tariff in advance of the anticipated

date of completion of the project based on the capital

expenditure actually incurred up to the date of making of the

application or a date prior to making of the application, duly

audited and certified by the statutory auditors, and the

provisional tariff shall be charged from the date of commercial

operation of the respective unit of the generating station or the

line or sub-station of the transmission system;

2. A generating company or the transmission licensee shall make a

fresh application as per Appendix I to these regulations, for

determination of final tariff based on actual capital expenditure

incurred up to the date of commercial operation of the

generating station or the transmission system, duly audited and

certified by the statutory auditors.

Core Business

For the purpose of these regulations, core business means the regulated

activities of generation or transmission of electricity and does not

include any other business or activity, like consultancy,

telecommunication, of the generating company or the transmission

licensee.

Tax on Income

• Tax on the income streams of the generating company or the

transmission licensee, as the case may be, from its core business, shall

be computed as an expense and shall be recovered from the

beneficiaries.

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• Any under-recoveries or over-recoveries of tax on income shall be

adjusted every year on the basis of income-tax assessment under the

Income-Tax Act, 1961, as certified by the statutory auditors.

1. Provided that tax on any income stream other than the core

business shall not constitute a pass through component in tariff

and tax on such other income shall be payable by the generating

company or transmission licensee, as the case may be.

2. Provided further that the generating station-wise profit before

tax in the case of the generating company and the region-wise

profit before tax in case of the transmission licensee as

estimated for a year in advance shall constitute the basis for

distribution of the corporate tax liability to all the generating

stations and regions.

3. Provided further that the benefits of tax-holiday as applicable in

accordance with the provisions of the Income-Tax Act, 1961

shall be passed on to the beneficiaries.

4. Provided further that in the absence of any other equitable basis

the credit for carry forward losses and unabsorbed depreciation

shall be given in the proportion as provided in the second

proviso to this regulation.

5. Provided further that income-tax allocated to the thermal

generating station shall be charged to the beneficiaries in the

same proportion as annual fixed charges, the Income-tax

allocated to the hydro generating station shall be charged to the

beneficiaries in the same proportion as annual capacity charges

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and in case of interstate transmission, the sharing of income-tax

shall be in the same proportion as annual transmission charges.

Tax Escrow Mechanism

• The beneficiaries shall maintain an interest bearing tax escrow

account in a scheduled bank, to which all amounts of interest shall

be credited.

• The tax liability shall be estimated two months before the

commencement of each Year and intimated to the beneficiaries.

The generating company or the transmission licensee shall

endeavor to minimize its liability on account of taxes recoverable

from the beneficiaries.

• The generating company or the transmission licensee shall be

authorised to withdraw the amounts for settling the income-tax

liability on presentation to the escrow holder, a certificate from

their statutory auditors that the amounts are immediately due and

payable to the taxing authority.

• The generating company or the transmission licensee shall pay into

the tax escrow account any refund received from the taxing

authority.

• The refunds, if any, shall not be paid back to the beneficiaries and

shall be adjusted in the escrow account. Any balance due or

returnable shall be rolled over to the next year.

• The escrow accounts shall be reflected in the books of accounts of

the beneficiaries as their bank account.

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Extra Rupee Liability

• Extra rupee liability towards interest payment and loan repayment

corresponding to the normative foreign debt or actual foreign debt, as

the case may be, in the relevant year shall be permissible provided it

directly arises out of Foreign Exchange Rate Variation and is not

attributable to the generating company or the transmission licensee or

its suppliers or contractors. Every generating company and the

transmission licensee shall recover Foreign Exchange Rate Variation

on a year to year basis as income or expense in the period in which it

arises and Foreign Exchange Rate Variation shall be adjusted on a year

to year basis.

Recovery of Income-tax and Foreign Exchange Rate Variation

• Recovery of Income-tax and Foreign Exchange Rate Variation shall be

done directly by the generating company or the transmission licensee,

as the case may be, from the beneficiaries without making any

application before the Commission.

Provided that in case of any objections by the beneficiaries to the amounts

claimed on account of income-tax or Foreign Exchange Rate Variation, the

generating company or the transmission licensee, as the case may be, may

make an appropriate application before the Commission for its decision.

Deviation from norms

Tariff for sale of electricity by a generating company may also be determined

in deviation of the norms specified in these regulations subject to the

conditions that:

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• The overall per unit tariff of electricity over the entire life of the asset,

calculated on the basis of the norms in deviation does not exceed the

per unit tariff calculated on the basis of the norms specified in these

regulations; and

• Any such deviation shall come into effect only after approval by the

Commission.

In case of the existing generating stations, TPS-I and TPS-II (Stage I & II) of

Neyveli Lignite Corporation Ltd, whose tariff was initially determined by

following Net Fixed Assets approach based on mutual agreement between

Neyveli Lignite Corporation Ltd and the beneficiaries, tariff shall continue to

be determined by adopting Net Fixed Assets approach.

Power to Remove Difficulties

If any difficulty arises in giving effect to these regulations, the Commission

may, of its own motion or otherwise, by an order and after giving a reasonable

opportunity to those likely to be affected by such order, make such provisions,

not inconsistent with these regulations, as may appear to be necessary for

removing the difficulty.

Power to Relax

The Commission, for reasons to be recorded in writing, may vary any of the

provisions of these regulations on its own motion or on an application made

before it by an interested person.

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Determination of Tariff (under Electricity Act. 2003)

62. (i) The Appropriate Commission shall determine the tariff in accordance

with provisions of this Act for –

(a) Supply of electricity by a generating company to a distribution

licensee:

Provided that the Appropriate Commission may, in case of shortage of supply

of electricity, fix the minimum and maximum ceiling of tariff for sale or

purchase of electricity in pursuance of an agreement, entered into between a

generating company and a licensee or between licensees, for a period not

exceeding one year to ensure reasonable prices of electricity;

(b) Transmission of electricity;

(c) Wheeling of electricity;

(d) Retail sale of electricity.

Provided that in case of distribution of electricity in the same area by two or

more distribution licensees, the Appropriate Commission may, for promoting

competition among distribution licensees, fix only maximum ceiling of tariff

for retail sale of electricity.

ii. The Appropriate Commission may require a licensee or a generating

company to furnish separate details, as may be specified in respect of

generation, transmission and distribution for determination of tariff.

iii. The Appropriate Commission shall not, while determining the tariff

under this Act, show undue preference to any consumer of electricity but

may differentiate according to the consumer's load factor, power factor,

voltage, total consumption of electricity during any specified period or

the time at which the supply is required or the geographical position of

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any area, the nature of supply and the purpose for which the supply is

required.

iv. No tariff or part of any tariff may ordinarily be amended more frequently

than once in any financial year, except in respect of any changes

expressly permitted under the terms of any fuel surcharge formula as

may be specified.

v. The Commission may require a licensee or a generating company to

comply with such procedures as may be specified for calculating the

expected revenues from the tariff and charges which he or it is permitted

to recover.

vi. If any licensee or a generating company recovers a price or charge

exceeding the tariff determined under this section, the excess amount

shall be recoverable by the person who has paid such price or charge

along with interest equivalent to the bank rate without prejudice to any

other liability incurred by the licensee.

Determination of Tariff by Bidding Process

63. Notwithstanding anything contained in section 62, the Appropriate

Commission shall adopt the tariff if such tariff has been determined through

transparent process of bidding in accordance with the guidelines issued by the

Central Government.

Procedure for Tariff Order

64. (1) An application for determination of tariff under section 62 shall be

made by a generating company or licensee in such manner and accompanied

by such fee, as may be determined by regulations.

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(2) Every applicant shall publish the application, in such abridged form and

manner, as may be specified by the Appropriate Commission.

(3) The Appropriate Commission shall, within one hundred and twenty days

from receipt of an application under sub-section (1) and after considering all

suggestions and objections received from the public,-

Issue a tariff order accepting the application with such

modifications or such conditions as may be specified in

that order;

Reject the application for reasons to be recorded in

writing if such application is not in accordance with the

provisions of this Act and the rules and regulations made

there under or the provisions of any other law for the

time being in force:

Provided that an applicant shall be given a reasonable opportunity of being

heard before rejecting his application.

(4) The Appropriate Commission shall, within seven days of making the

order, send a copy of the order to the Appropriate Government, the Authority,

and the concerned licensees and to the person concerned.

(5) Notwithstanding anything contained in Part X, the tariff for any inter-State

supply, transmission or wheeling of electricity, as the case may be, involving

the territories of two States may, upon application made to it by the parties

intending to undertake such supply, transmission or wheeling, be determined

under this section by the State Commission having jurisdiction in respect of

the licensee who intends to distribute electricity and make payment therefore:

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(6) A tariff order shall, unless amended or revoked, shall continue to be in

force for such period as may be specified in the tariff order.

Provision of Subsidy by State Government

65. If the State Government requires the grant of any subsidy to any consumer

or class of consumers in the tariff determined by the State Commission under

section 62, the State Government shall, notwithstanding any direction which

may be given under section 108, pay, within in advance in the manner as may

be specified, by the State Commission the amount to compensate the person

affected by the grant of subsidy in the manner the State Commission may

direct, as a condition for the license or any other person concerned to

implement the subsidy provided for by the State Government:

Provided that no such direction of the State Government shall be operative if

the payment is not made in accordance with the provisions contained in this

section and the tariff fixed by State Commission shall be applicable from the

date of issue of orders by the Commission in this regard.

Development of Market

66. The Appropriate Commission shall endeavor to promote the development

of a market (including trading) in power in such manner as may be specified

and shall be guided by the National Electricity Policy referred to in section 3

in this regard.

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AVAILABILITY BASED TARIFF (ABT)

ABT has been under discussion since 1994 when M/s ECC, an ADB

consultant, first supported it. GOI constituted a National Task Force in

February 1995. It had ten meetings till end 1998 where all the related issues

were discussed. A draft notification was prepared for issue by government.

With effect from May 15, 1999 the jurisdiction was vested in the CERC.

Papers were sent to the Commission in June 1999 by the MoP. The

proceedings were held in the Commission from July 26 to 28, 1999. The ABT

order dated January 4, 2000 of the Commission departs significantly from the

draft notification as also from the prevailing tariff design.

Why ABT?

1. India plans to have an integrated National Grid. This will assist in meeting

demand with the least cost supply. Five Regional grids already exist. Some

linkages between Regions are also in place.

1. The five Regional grids work at vastly varying operational parameters

today. Frequency level is one such operational parameter. The target

frequency prescribed by the Indian Electricity Rules is 50 Hz

2. Integrated grid operations require the normalisation of frequency

across all five Regions. The alternative is to insulate each Regional

Grid by Back to Back HVDC links. This is an expensive option.

Normalisation of frequency requires proactive load management by

beneficiaries and despatch discipline by generators.

3. There is currently no formal system of financial incentives to promote

grid discipline.

4. The ABT provides this mechanism.

2. Chronic surpluses in the East and shortages in the South, have resulted in

sustained functioning of these grids at frequencies which are far beyond even

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the normal band, liberally defined by the IEGC as frequency variation within

49.5 to 50.3 Hz

1. Continued functioning at non-standard frequency results in long-term

damages to both generation and end use equipment. This is a “hidden

cost” which is borne by the customer in the long term.

2. The ABT will induce corrections in the prevailing frequency to bring it

within the permissible band.

3. Frequent fluctuations in frequency caused by short-term variations in the

demand supply gap due to the tripping of load or outage of a generator or a

transmission line impose substantial costs on generators and consumers.

1. The ABT will address this problem by inducing grid discipline.

4. Economic efficiency dictates that least cost power should be despatched in

preference to more costly power (merit order despatch). This becomes

difficult without a two part tariff for all stations. States tend to compare the

total cost of central generators with the variable cost of their own stations,

since for them the fixed costs of state level stations are sunk costs. These

results in making central generation appear artificially more expensive than

state level stations even though on variable cost basis the former may be

cheaper.

1. The two-part tariff of the ABT by making the payment of fixed cost a

fixed liability of the states converts it into a sunk cost thereby levelling

the playing field between central generators and state level plants.

5. Currently beneficiaries are not liable for payment of the fixed cost

associated with the share of capacity allocated to them. If a beneficiary

decides not to draw any energy he can escape payment of the fixed charge,

which then gets paid by the person drawing energy. This is unfair since it

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increases the cost of energy even for those beneficiaries who may be drawing

energy within their entitlements.

1. The two-part tariff of the ABT assures that each beneficiary will be

liable for payment of the fixed cost associated with its share of

allocated generation capacity.

6. Currently generators have a perverse financial incentive to go on generating

even when there may be no demand. This results in high frequency in the grid

as is endemic in the East

1. The ABT will discourage such behaviour by pricing generation outside

the schedule in relation to the prevailing frequency.

What Is ABT?

• It is a performance-based tariff for the supply of electricity by

generators owned and controlled by the central government.

• It is also a new system of scheduling and despatch, which requires

both generators and beneficiaries to commit to day-ahead schedules.

• It is a system of rewards and penalties seeking to enforce day ahead

pre-committed schedules, though variations are permitted if notified

One and one half hours in advance.

• The order emphasises prompt payment of dues. Non-payment of

prescribed charges will be liable for appropriate action under

sections 44 and 45 of the ERC Act.

It has three parts:

- A fixed charge (FC) payable every month by each beneficiary to the

generator for making capacity available for use. The FC is not the same for

each beneficiary. It varies with the share of a beneficiary in a generators

capacity. The FC, payable by each beneficiary, will also vary with the level of

availability achieved by a generator.

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- In the case of thermal stations like those of NLC, where the fixed charge has

not already been defined separately by GOI notification, it will comprise

interest on loan, depreciation, O&M expenses, ROE, Income Tax and Interest

on working capital.

- In the case of hydro stations it will be the residual cost after deducting the

variable cost calculated as being 90% of the lowest variable cost of thermal

stations in a region.

- An energy charge (defined as per the prevailing operational cost norms) per

Kwh of energy supplied as per a pre-committed schedule of supply drawn

upon a daily basis.

- A charge for Unscheduled Interchange (UI charge) for the supply and

consumption of energy in variation from the pre-committed daily schedule.

This charge varies inversely with the system frequency prevailing at the time

of supply/consumption. Hence it reflects the marginal value of energy at the

time of supply.

How is ABT different from normal proceedings to determine generation

tariff?

1. The ABT proceeding has not attempted to consider most of the cost drivers

like ROE, Operational Costs, depreciation rate, composition of the Rate Base,

capital structure etc. Proceedings to redefine these norms are being held

separately. Hence the ABT proceedings have been concerned more with tariff

design rather than definition of tariff norms or determination of tariff levels.

2. Its incidence is a function not only of the behaviour of a generator but also

of the behaviour of a beneficiary. Disciplined beneficiaries and generators

stand to gain. Undisciplined beneficiaries and generators stand to lose.

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Broad features of ABT design

1. It implements the long held view that electricity tariffs should be two-

part comprising a fixed charge and a separate energy charge.

2. It increases the target availability level at which generators will be able

to recover their fixed costs and ROE from 62.79% deemed PLF at

present to 80% (85% after one year) for all thermal stations, 85% for

Hydro in the first year and 77% (82% after one year) for NLC.

3. Misdeclaration of availability entails severe penalties.

4. It rationalises the relationship between availability level and recovery

of fixed cost.

The draft notification provided for recovery of (annual fixed costs

minus ROE) at 30% availability and recovery of ROE on pro-rata basis

between 30% and 70% availability. This order provides for payment of

capacity charges between 0% and target availability (as indicated in

item 2 above) on pro-rata basis.

5. The draft notification had provided for payment of capacity charges for

prolonged outages. This order disallows such payments.

6. It delinks the earning of incentive from availability and links it instead

to the actual achievement of generation. Hence incentives will be

earned by generators only where there is a genuine demand for

additional energy generation unlike the prevailing situation, or the

proposed draft received from the GOI, under which it is earned purely

because the generator is available.

7. Draft notification linked incentives to equity. This order preserves the

status quo of one paise per Kwh per each 1% increase in PLF above

target availability.

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8. It increases the minimum performance criterion for the earning of an

incentive from 68.5% deemed PLF at present to 80% (85% after one

year) for all thermal stations, 85% for Hydro and 77% (82% after one

year) for NLC.

9. It introduces severe financial penalties for grid indiscipline along with

significant rewards for behaviour, which enforces grid discipline for

both generators as well as beneficiaries.

10. The order permits market pricing for the trading of surplus energy by

beneficiaries and generators.

11. The order urges the GOI to allocate the unallocated capacity a month

in advance so that beneficiaries know their exact share in capacity in

advance and can take steps to trade surplus power.

12. It will be implemented in stages from April 1, 2000 starting from the

South. The new norm for incentive will however be applicable from

this date for all central stations. In the case of NPC, GOI to decide

applicability of the order.

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COMPARISON OF EXISTING TARIFF SYSTEM AND AVAILABILITY BASED TARIFF

Sl. No.

Description of Item

Existing System

Draft ABT Proposal

ABT Order

1. Capacity / Fixed Charge

Annual Fixed Charge (AFC) include : a) Interest on loan b)Depreciation c)O&M d)Return on Equity e) Income-Taxf) Interest on Working Capital

Fixed charges excluding ROE i.e. all other five items of the existing system. ROE treated separately

Capacity charge as per existing system

2. Basis of recovery

Recovered at 62.79% deemed PLF. 50% AFC at 0% PLF and full recovery at 68.49% deemed PLF.

FC excluding ROE recovered at 30% availability on pro-rata basis between 0% and 30% availability. ROE recovered on pro-rata availability between 30% and 70%

Pro-rata recovery of capacity charge for i) NTPC stations: Between 0 to 80% availability in the first year and 0 to 85% availability in the second year ii) NLC Stations Between 0 to 77% availability in the first year and 0 to 82% availability in the second year iii) NHPC Stations Between 0 to 85% availability in the first year and availability in the second year to be announced by the commission separately.

3. Incentives Above 68.49% deemed PLF, incentives at 1 paise/KWh for each 1% increase in

Incentive beyond target availability of 70% is as follows:

1 paise/KWh/each percentage increase in PLF of 80%/ 85% in the first/ second year for NLC and 85% in the first year for

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PLF. 70% to 85% - 0.4% of equity for each 1% increase in availability beyond 85%.

NHPC.

4. Sharing of fixed cost

Based on actual energy drawls

Based on allocated capacity

Based on allocated capacity

5. Recovery of variable cost

Based on actual energy drawls

Based on Scheduled Energy

Based on Scheduled Energy

6. Deviations from schedule – UI charges

No penalties for such deviation

Varying between 0 to 360 paise/Kwh for the frequency range of 50.5 Hz to 49 Hz

Varying between 0 to 420 paise/Kwh for the frequency range of 50.5 Hz to 49 Hz

7. Norms for tariff determination

GOI Tariff notification

GOI Tariff notification

GOI Tariff notification till such time Commission finalises its views

8. Procedure for payment of capacity charge if ABT is introduced in the middle of a financial year

Not applicable Not specified

Specified

9. Prolonged Outages

Included in item (2) above

Provided for payment of adjusted capacity charges

Does not provide for payment of capacity charges

10. Marketing of surplus energy

Not applicable Not specified

Encouraged and will not require commission’s approval

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11. Splitting up of capacity and energy charge for hydro stations.

Capacity charge covered depreciation and interest on loan. Energy covered ROE, income tax, O&M and interest on working capital.

Capacity charge covered depreciation and interest on loan. Energy covered ROE, income tax, O&M and interest on working capital.

Till such commission notifies peak and off-peak energy rates for hydro-stations, primary energy charge would be taken as 90% of the lowest variable charge of the thermal power station in the concerned region. The balance of total charges would be recovered as capacity charges.

12. Payment of dues to generators

As per agreements

As per agreements

As per orders of the commission

13. Applicability All central generating stations

All central generating stations staggered region wise

i) ABT implementation is staggered region wise ii) Fixed charge recovery and basis for incentive payments revised from 1st April, 2000. iii) GOI to decide about ABT for automatic power stations.

14. PLF for incentives during interim period

Not applicable Not specified

Till the introduction of ABT in other regions and after 1.4.2000, the actual PLF for incentive purposes for NTPC shall be 80% instead of deemed PLF of 68.49%. The PLF in the first year for incentive purposes for NHPC shall be 85%.

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Open Access: Methods for Calculation of Cross-Subsidy Surcharge and

Assessment of the Financial Impacts on Utilities

Introduction

In order to promote competition in the electric power sector, the Electricity

Act 2003 (E. Act) mandates open access to the transmission and distribution

network for any supplier of electricity. With open access, upon approval by

the Electricity Regulatory Commission (ERC), competing suppliers will be

able to provide electricity to certain categories of consumers and thus bring

competition into generation and supply of electricity. A major complication in

the transition to competition is the loss of cross-subsidy revenues that were

being provided by the exiting consumer to fund the subsidized (below cost

provision of) supply to the majority of LT consumers.

The EAct has attempted to compensate the utilities by allowing State

Commissions to impose surcharges on those consumers leaving the licensee

and receiving power from competing suppliers. However, the wording of the

Act on these issues is not clear regarding the level of the surcharges and the

method of their calculation. For this reason, the EAct is subject to multiple

interpretations and there have been several suggestions for how these

surcharges are to be calculated.

Here we describe the recommendations made by various parties regarding the

method of calculation and level of the surcharges. Then we discuss our

concerns about these recommendations. Next, we assess the likely revenue

loss for licensees due to open access and the extent to which the various

recommended methods would compensate the utilities for the revenue loss.

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We’ve discussed the conflicting requirements for making open access

economically attractive and protecting the financial health of utilities. We

conclude with suggestions on other factors that need to be considered to make

the transition to competition a little smoother.

Recommendations by Various Parties on Mechanisms to Calculate the

Cross- Subsidy Surcharge

Electricity Act 2003

The EAct allows open access before cross-subsidies are eliminated through

the payment of a surcharge but requires that the subsidies be progressively

reduced in a manner determined by the State Commission. Clarifying the

purpose of the surcharge, the Act states that the surcharge is to “meet the

requirements of current level of cross subsidy within the area of supply of the

distribution licensee.” While the Act is silent on the method to be used to

calculate the cross-subsidy surcharge, it clearly states that the State

Commission will determine the cross-subsidy surcharge and the manner in

which it will be progressively reduced. However, the EAct requires that the

State Commissions be guided by the National Electricity Policy, National

Electricity Plan, and Tariff Policy which are to be notified by the Ministry of

Power (MoP). Thus these policies will also have an influence on the

calculation of the cross-subsidy surcharge to be decided by the State

Commissions.

First Draft of Tariff policy paper by MoP

MoP prepared a Preliminary Discussion Paper on Tariff Policy with the

assistance of CRISIL, which mentions that, the “Commission would decide

the surcharge such that the loss of cross-subsidy is shared between the

consumer and the incumbent distribution licensee.” This statement is an

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interpretation/ extension of the EAct, because the EAct does not mention any

sharing of the cross-subsidy but simply states “…such surcharge shall be

utilised to meet the requirements of current level of cross subsidy…”

Draft National Electricity Tariff Policy as recommended by the Task Force

The Report of the Task Force on Power Sector Investments and Reforms

dated February 2004 included a draft tariff policy in which it recommended

that the cross-subsidy surcharge for open access be computed based on the

Long Run Incremental Costs (LRIC).

In its recommendations, the Task Force said that the cross subsidy surcharge

should represent the difference between the actual tariffs and LRIC. The

Report went on to say that the appropriate Commission should conduct the

necessary studies to determine LRIC or have the studies carried out by the

licensees. It suggested that in the interim the costs of the most expensive

generating unit (based on both fixed and variable costs) be used as a proxy for

LRIC. In October 2004, the Ministry of Power (MoP) recommended to the

Planning Commission that it take note of these recommendations of the Task

Force while formulating policy on the cross-subsidy surcharge.

Other Recommendations

Sankar (2004) discusses two alternatives for determining the surcharge. He

looks at the cross-subsidy as either: (1) the HT tariff minus the average cost of

supply; or (2) the HT tariff minus the cost to serve the HT consumer class.

Using the example of AP, he estimates the cross-subsidy surcharge to be Rs

1.65 per kWh and Rs. 2.05 per kWh based on the two methods respectively.

He argues that simply using either of these approaches will result in a high

cross subsidy surcharge that would make open access meaningless and stall

reforms of the power sector. Mr. Sankar recommends that the National

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Electricity Policy or the Tariff Policy should define the cross subsidy paid by

a consumer class as the difference between the tariff for that consumer class

and the average cost of supply. He further recommends that the surcharge be

only a fraction, say 50 percent, of the present level of cross-subsidy. He

considers it reasonable to fix the surcharge at a fraction of the cross-subsidy

because according to him the consumer opting for open access is taking a

greater risk than one that stays with the utility. Furthermore, he says that to

make open access meaningful, the cost of supply from open access including

the surcharge should be less than the grid tariff. As an alternative, Mr. Sankar

suggests that the marginal cost of power purchase be used as the cost to serve

in calculating the surcharge.

A Consultation Paper prepared by NCAER for CERC titled Introducing

Competition in Generation of Electricity, recommends that the surcharge be

subject to a ceiling determined by the following equation:

Max. Surcharge = Tariff for departing consumer – Marginal cost of supply

for the discom

“As an alternative formulation” the paper recommends that the surcharge not

be greater than 20 percent of the average price of power procured by the

DISTCOs in the preceding financial year. In most cases, the alternate

formulation would result in a much lower surcharge.

Concerns with Recommended Methods for Calculating the Cross-

Subsidy Surcharge

Issues with the Use of LRIC*

The Task Force Report does not give a reason for recommending that the

difference between the actual tariffs and LRIC (Long Run Incremental Cost)

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be used for calculating the cross-subsidy surcharge. Clearly, the LRIC do not

represent the current cost to serve the existing customer, but could be seen as

a proxy for the costs that will be avoided by the utility.

Cross-subsidy revenues are equal to the difference between the revenue

generated by a customer and the cost to serve that customer. Cost to serve is

based on an allocation of total costs to different customer categories. In

contrast, LRIC are akin to marginal costs. By using LRIC as a proxy for cost

to serve, one is allocating the costs of new additions to a single consumer

category (HT consumers). But actually while calculating the cost to serve, the

cost of new additions is merged with existing costs so that the cost of capacity

additions are spread across all categories of consumers. Therefore, by using

LRIC as a proxy for cost to serve, one is overstating the cost to serve if LRIC

is greater than the average of the existing costs, and one is understating the

cost to serve if LRIC is less than the average existing costs. Usually LRIC is

higher than the existing costs so the cost to serve would be overstated

resulting in a smaller surcharge.

Furthermore, if HT load leaves the system much faster than the expected load

growth, then capacity additions will not be required for some time but instead

the utility may have to pay for existing fixed costs that cannot be avoided. In

that case, the avoided costs will be zero, and instead, there will be stranded

costs. Thus we see that for cases of rapid departure of HT load, the use of

LRIC (based on capacity additions) will significantly overstate the avoided

costs and understate the surcharge required*.

*- Long Run Incremental Cost

*- Another issue with the use of LRIC is that estimating LRIC can be difficult

because these are forward looking costs which are based on forecasts. There

can be great variations in the forecasts made by different parties and the

regulatory agency must decide whose forecast is the most reliable. This is

often not easy.

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Issues with the Use of Marginal Unit Cost (MUC)

We have several concerns with the use of MUC to calculate the surcharge.

First, MUC do not represent avoidable costs. Generally, the fixed costs of the

marginal unit are not avoidable. If the licensee’s load is reduced because of

the departure of some customers, at best the licensee will avoid the highest

variable cost of either its own plants or the plants from which it purchases

power. In those cases where the marginal unit for a utility may be an

unplanned purchase from a surplus area or the unallocated portion of a

Central Generating Station (CGS), the utility may be able to avoid both the

fixed and variable costs of the contract.

The second reason why it is inappropriate to use MUC to calculate the

surcharge is that this assumes that for any utility, there is a single generating

unit that is on the margin at all times, and that is not so. The generating unit

on the margin changes with the time of day and season. During peak periods,

peaking units with very high variable costs are on the margin while during

off-peak periods, baseload units with very low variable costs may be on the

margin, etc.. Thus generally the most expensive unit would be the one that

operates only at the times of the system peak (and hence would have a low

PLF) and applying that cost to all the 8760 hours3 of the year would lead to a

gross overstatement of the avoidable costs.

The third problem with the use of MUC to calculate the surcharge is that the

highest cost unit is not applicable to the entire decrement of load. The use of a

single unit (the highest cost unit) to represent avoidable costs for all the load

that would go out due to open access is likely to be incorrect. As an example,

consider that 1000MW of industrial load is expected to leave the licensee and

get electricity from alternative suppliers. If the capacity of the highest cost

generating resource is only 200 MW, then clearly it would be incorrect to

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assume that the costs per kWh of the 200 MW units would be applicable to

the entire 1000 MW load block. The avoidable costs for the remaining 800

MW would be lower. Therefore, the size of the decrement of load for

calculating the avoidable costs must match the expected decrement in load

due to open access. The avoidable cost would then be the weighted average of

the costs of the generating units that would no longer be required.

These concerns with the use of MUC to calculate the surcharge are best

illustrated by calculating the surcharge for different states by strictly

following the recommendations for the use of MUC. For AP and

Maharashtra, the total costs (fixed plus variable) of the marginal generating

unit per kWh are higher than the tariff for HT industrial consumers.

Therefore, if the recommendations for the use of MUC are strictly followed,

we get a negative cross-subsidy surcharge. The main reason for this

anomalous result is that the marginal unit operates for a very short time in the

year and it is incorrect to apply its costs to a load decrement that covers most

of the hours of the year.

Issues with the Use of the Average Cost of Supply

If the average cost of supply is used to calculate the surcharge, then the

resulting revenues will not completely compensate the licensee for the loss of

cross-subsidizing revenues. This can be seen from the following calculation:

Cross-subsidizing revenues provided by HT consumers = HT tariff - Cost to

Serve HT consumers

If the average cost of supply is used to calculate the surcharge, then

Surcharge using average cost of supply = HT tariff – Average Cost of Supply

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Therefore, the revenue deficit due to the use of average cost of supply is given

by the following equation:

Cross-subsidizing revenue deficit = Average cost of supply – Costs to Serve

HT Consumers

How large would be this deficit due to the use of average cost of supply

instead of cost to serve? We consider the case of AP, where the HT tariff is

4.11 Rs/kWh; the average cost of supply is 2.82Rs/kWh, and the cost to serve

HT consumers is 2.61 Rs/kWh. Using the equations given above, we see that

the revenue deficit would be Rs 0.21 per kWh. The total HT sales for

Category I and II consumers for the year are projected to be 7297 MU, so if

half the HT load opts for open access, then the revenue deficit will be Rs. 77

crores per year. If, for calculating the surcharge, the average cost of supply is

reduced by 50% as suggested, then the loss will be Rs. 312 crores per year.

HT Energy Audit: The Crucial Starting Point for Curbing Revenue Loss

Introduction

For the last two decades, the financial crisis besetting the Indian power sector

has been an issue of great concern for the planners and experts. In 1990s, the

discussion on this crisis was focused on the large subsidies for agricultural

consumers and the rapid growth in agricultural power consumption. It is

worth noting that this preoccupation with agricultural tariff and subsidy

persisted in spite of efforts on the part of some researchers to point out

another crucial causative factor. These researchers had been pointing out that

excessive transmission and distribution (T&D) losses, hidden under the garb

of agricultural consumption, had been a major cause for the poor financial

health of utilities (Roy 1996, Reddy and Sumithra 1997, Dixit and Sant 1997).

However, most experts and leaders of the sector continued with their

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preoccupation with the agricultural subsidy without serious investigation into

this crucial factor.

In the last few years, especially after establishment of the independent state

electricity regulatory commissions (SERCs), many state utilities are revising

their T&D loss estimates from the earlier lower figures of around 18-20% to

anything in the range of 35% to 50%. With this, it is now being widely

accepted that reduction in T&D losses to a reasonable level is essential for

restoring financial viability of the utilities*.

* A calculation for Maharashtra state utility indicates that financial loss due to

excessive T&D loss (defined as that above 25%) is about Rs 2,500 crores p.a.

And, this is more than the agricultural subsidy that is claimed to be\ Rs. 2,100

crores p.a.

However, the belated acceptance of excessive T&D losses has resulted in

considerable delay in action to reduce these losses, which is proving

extremely costly. Nonetheless, it is a welcome sign that the issue of T&D

losses is coming into limelight now and different approaches are being

suggested as prescriptions to address the issue.

This section highlights the large swings that have been occurring in the

estimation of T&D losses in various states as well as the prevailing

uncertainty in estimation of even transmission losses and HT-level losses.

Based on experiences from the states such as Haryana, Maharashtra and

Andhra Pradesh, the third section highlights unwillingness on the part of

utilities to carry out effective metering even at the HT level. The fourth

section points out that commercial loss even at the HT-level might be

significant in terms of revenue lost per customer as well as of the total

revenue loss. The fifth section discusses various advantages of focusing on

HT-level energy audit for increase in utilities revenue. The sixth section

argues that the approaches of “100% Metering” and “Total Energy Audit”

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(including LT energy audit) though essential, would, at best, yield

significant benefits only in the long term. The last section presents the

conclusions of this analysis.

1. Swings in the Estimates of T& D Losses

The first step in the efforts for reducing excessive T&D losses is to properly

estimate T&D losses. The next and probably more important step in these

efforts is to identify various links or geographical areas in the network that

have excessive losses. It is possible that losses in some of these areas or links

could be easier to curb as compared to losses in other links/areas.

Identification of such links / areas makes it possible to focus initial efforts for

reduction in T & D losses on these areas or links. The next two sub-sections

demonstrate that, though SERCs and

Chart 5: T& D Loss determination between four states

Figure highlights changes in the estimated T&D losses in various states. The state utilities have attempted a more realistic estimation of T&D losses during the regulatory process. In states such as Maharashtra and Haryana, the upward revision of loss estimates has been much higher than the RC targeted loss reduction. The bar sequence for Karnataka has been changed as Karnataka utility did two substantial revisions in the loss estimate before the KERC—s first tariff order.

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Utilities are making efforts to identify such links / areas of high losses; there

is still significant uncertainty and differences over the real level of total as

well as Transmission and HT losses.

2. T&D Loss Estimation

Analysis of regulatory orders by SERCs from different states indicate that,

even two to three years after establishment of the SERCs and the reforms

process, there is still ambiguity over the real level of T&D losses. Figure 1

shows changes in the estimate of T&D losses in the four states.

State after state has revised the figures for T&D losses upward in the last few

years. This has happened in some typical steps. First, as a prelude to the

setting up of the SERCs, the state utilities typically increased the loss

estimates from the historical low values to a more realistic level.

Subsequently, SERCs ordered reduction in T&D losses, usually by around by

5-7 percentages point. As against this target of lowering T&D losses the

utilities have come back to SERCs with further revised estimates of losses,

which are typically 5 to 10 percentage points more than their earlier estimates.

This resulted in SERCs (as in the case of Maharashtra & Haryana) approving

higher loss levels in subsequent orders. The Maharashtra ERC revised

approved loss levels from 27% to 36%, whereas the Haryana ERC revised

approved loss levels from 25% to 41%*.

*Though the MERC order does not explicitly state the approved loss level, it

is back calculated based on the loss level projected by MSEB and additional

revenue from commercial loss reduction as directed by MERC.

For explaining these upward changes in the T&D loss estimates, the utilities

cite some typical reasons such as (a) increased (and hence ’better—) sample

of agricultural consumers used for estimation of their average hours of

consumption and (b) changes in assumed usage level (i.e. load factor) of the

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un-metered domestic or commercial consumers. Additionally, the utilities

have argued that it is impossible to reduce T&D losses to the levels envisaged

and desired by the SERCs in a period of four to five years. The state utility in

Delhi (viz., Delhi Vidyut Board) has produced evidence of international

experience in support of this argument. Some utilities have also argued that,

in order to achieve the significant reduction in T&D losses, they will have to

police the entire state to curb the rampart power theft. Unfortunately, none of

the utilities in the country, whether private or public, has been able to reduce

the T&D losses to the level mandated by the SERCs.

3. Estimation of Transmission and HT Losses

Measurement or even estimation of T&D loss in the LT (low voltage /

tension) system is a difficult task, as the LT network connects millions of

small consumers spread across the country and even into remote and

inaccessible areas. However, unlike the LT system, the transmission or high-

tension (HT, i.e., 11 kV and above) network connects only to a few thousand

large consumers. Hence, it is much easier to monitor the HT network. Due to

the large volume of electricity flows in the HT network, monitoring and

protection systems are already in place in the HT network. For example, at

least by design, HT sub-stations are provided with proper metering system to

measure feeder-wise incoming and outgoing energy flows.

As a result, one would expect that making correct measurement (or at least

estimation) of losses in the HT system would be easier and less prone to large

swings.

Unfortunately, most Indian utilities fall short even on this count. Let us

review the situation in this regard in the three- considered to be relatively

better managed- states of Maharashtra, Karnataka and Andhra Pradesh.

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Maharashtra

In its tariff proposal presented before the SERC in March 2000, Maharashtra

State Electricity Board (or MSEB) claimed that losses in its Extra HT (EHT)

network for the three previous years had been in the range of 3.8 % to 4.2%

(MSEB 2000). These estimates were based on the ’load-flow studies—

carried out by MSEB. As against this, MSEB, in its tariff proposal submitted

in August 2001, claimed that average EHT losses for the preceding six

months were 6.7% (starting with 8.4% and coming down to 4.8% in the last

month). This implied an upward revision by 2.7 %! (MSEB 2001). This

recent estimate seems to be based on the meter readings, but MSEB has not

provided estimate of technical losses (i.e., results of load-flow study) for this

period.

Karnataka

Karnataka Power Transmission Corporation Limited (KPTCL), the Karnataka

utility, had estimated transmission losses for the three consecutive years

(1999 to 2001) as 15.6%, 16.47% and 15.17%. Against this, the Karnataka

Electricity Regulatory Commission (KERC) pointed out that the studies

conducted by two consultants (viz. PRDC, Bangalore and MECON),

indicated transmission losses (up to 33 kV) to be around 10% (KERC 2000).

The estimates by the consultants were based on load-flow studies and on

meter readings, wherever available. Thus, here again, there is a large

difference of over 5 percent points in the estimation of just the transmission

losses.

Andhra Pradesh

The case of Andhra Pradesh (AP) is more revealing. In the first tariff proposal

before the Andhra Pradesh Electricity Regulatory Commission (APERC), the

state utility had claimed the transmission losses to be 4.6%. But, in the second

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tariff proposal, the utility claimed transmission (up to 132 kV level) loss level

to be 8.7%! The utility explained this upward revision in transmission losses

by saying that the earlier estimates had been based on load-flow studies,

whereas the revised losses were based on actual meter readings. As per the

utility—s claim, metered data in the period of the four months showed actual

transmission losses at the level of 9.6%, and after making certain adjustments

for ”metering accuracy and meter reading cycle time‘ etc. the utility estimated

the annual loss level to be at 8.7%. During the process of the review of the

‘Revenue Requirement’ APERC asked the utility to carry out a load-flow

study. Surprisingly, the utility was prompt in carrying out the load-flow study

and came out with an estimate of technical transmission losses to be 8.7%!

(APERC 2001). It is not a surprise, however, that there are serious lacunae in

the calculations in the load-flow study submitted by the utility.

To summarize, the above discussion indicates that even after a few years of

regulatory process, accurate estimation of ETH or HT losses is proving to be a

difficult task. To overcome this shortcoming, several SERCs have initiated

detailed technical studies with the help of external consultants to clearly

establish the technical losses at transmission / HT level. As discussed later,

estimation of technical losses at the HT level (through load-flow studies)

coupled with calculation of actual losses on the basis of energy audit would

lead to identification of commercial losses.

3. Unwillingness of Utilities for Effective HT Metering

Realizing the importance of proper energy audit for accurate estimation of

T&D losses and reduction in the same, several SERCs have directed the

utilities to undertake ”Total Energy Audit‘ and “100% Metering”. But, the

emerging evidence clearly demonstrate that the utilities are unable, rather

unwilling, to undertake “Energy Audit‘or”100% Metering’ even at the HT

level.

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Maharashtra

Maharashtra Electricity Regulatory Commission (or MERC), in its first tariff

order dated 5th May 2000, directed MSEB to install the ’Time-of-Day— (or

TOD) meters for all industrial HT consumers by September 2000 and for all

the remaining HT consumers by December 2000. It also directed MSEB to

furnish quarterly reports giving the number of these meters and data obtained

from the same. But, even six months after the target date, MSEB was able to

provide TOD meters only to half of the approximately 10,000 HT consumers.

MSEB—s performance has been equally awful in dealing with the task of

energy audit of its express feeders. Since 1994-95, MSEB has been claiming

that it is carrying out regular energy audit of selected urban areas as well as of

the Express Feeders (GoM, 1996). MSEB reiterated this claim in its tariff

proposal submitted in March 2000. It repeated this claim again in the proposal

submitted in August 2001.

However, this time, MSEB could actually make available the data compiled

from energy meters installed on about 220 ‘Express Feeders’ for the period of

six months. Out of the total 1320 data points (i.e., 6 months multiplied by 220

feeders), nearly 45% of these data points indicate loss figures that are either

less than -0.5% or greater than +5%! (Prayas 2001). This is striking because,

usually, the technical losses on such type of feeders should lie in the range of

1% to 2%. This implies that about half of the data points are indicating either

ineffective metering, commercial losses, or excessive technical losses. This is

a clear indication of MSEB—s failure to carry out effective metering even for

these 220 ’Express Feeders—. It is worthwhile to note that the energy

supplied through these 220 ‘Express Feeders’ account for nearly 20% of

MSEB’s yearly revenue (considering average HT industrial tariff of Rs

4.2/unit).

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Andhra Pradesh

The case of AP is more serious. In its tariff order dated 27 May 2000, APERC

directed the utility to install high-accuracy (i.e., the 0.2% accuracy class)

meters at all interface points (where the ownership of power changes from

one utility to other, i.e., from either generation to TRANSCO or from

TRANSCO to DISCO) and file a compliance report within one month, i.e., by

June 2000. Ten months later, in the subsequent tariff order dated 24th March

2001, APERC mentioned that the utility could implement this directive only

for 3% of the total interface points. Moreover, this order also reported that the

utility is demanding another full year to implement the directive! There is no

other way to term this delay as ridiculous, when one realizes that, in order to

comply with this directive, the utility had to install, in all, only 460 meters.

Haryana

The status of HT-level metering seems even more serious in the case of

Haryana. Haryana Electricity Regulatory Commission (HERC), in its tariff

order dated 26th November 1999, categorically mentioned that all interface

metering (where the ownership of power changes) should be completed latest

by 31st March 2000, i.e., within the period of four months. It went to the

extent of mentioning that “All metering would be completed by 31 March

2000 for all purposes including transmission and bulk supply tariff

application by the licensee. The Commission would not like to be presented

again with the plea of nonmetering for any purposes whatsoever after 31

March 2000” (emphasis original).

The utility failed to comply with this directive but went ahead and filed

another tariff revision application. In its subsequent tariff order in December

2000, HERC said, The Commission reiterates that this work should be given

high priority and no slippages beyond the targeted completion date of July

2001 will be allowed“(emphasis original) (p. 56, para 5.1.2.2). One would

expect that the utility would have followed this simple directive at least by the

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extended target date. But the scene repeated after few months. The subsequent

tariff order by HERC dated 6th August 2001 (Annex 3) also mentioned that,

till the date, the utility had failed to introduce interface meters as directed and

has, in fact, requested waiver of this directive! In the case of Haryana, the

total number of meters to be installed under this directive was about 300. This

failure of utility forced the SERC to estimate transmission losses on the basis

of data from other agencies such as regional electricity board and power grid.

To summarize, it is serious that utilities are taking SERCs for granted by not

implementing even such simple but crucial directives. Moreover, it goes

without saying, that the suggested prescription of T&D loss reduction through

‘100% Metering’ approach would be a non-starter if the utilities are unwilling

and / or unable to carry out metering and data-gathering tasks even at the

small number of locations, despite the full-knowledge of the high-stakes

involved in the energy flowing through these points.

4. Indication of Significant Commercial Losses at HT Level

The inability, rather unwillingness, of the utilities to install proper metering

even at the HT-level raises strong suspicion that all may not be well at the HT

level. Further analyses indicate possibilities of substantial commercial losses

even at the HT level.

Andhra Pradesh

As mentioned earlier, the transmission losses in AP as per the metered data

(for a period of four months) were 9.6% (APERC 2001). The utility applied

some corrections and arrived at the estimate of the annual losses of 8.7%

based on the meter data. The utility justified this loss-level as the technical

losses using a load-flow study. This study found the peak power losses to be

9.66%. The utility then used an assumed figure of 90% for the ’Load Factor—

and multiplied the peak power losses with the assumed Load Factor to arrive

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at the estimate of technical losses as 8.7%. This calculation for technical

losses is flawed because the ’Load Factor— (i.e., average load divided by

peak load) for the utility was about 70% and not 90%. Using correct load

factor indicates technical losses of 6.7% i.e. around 2% less than losses

indicated by metered data. The APERC has recently engaged the CPRI

(Central Power Research Institute) for estimation of technical transmission

losses.

Maharashtra

In case of MSEB, indication of the possibility of substantial commercial loss

at the HT level emerges from the analysis of the energy audit data of the

Express Feeders supplied by MSEB, which is mentioned earlier. Out of the

220 Express Feeders, nearly 40% of the feeders show consistently

problematic readings. These include either no reading or the reading showing

losses outside the range of (- 0.5%) to (+5 %) for four or more months out of

the six-month period! (Prayas 2001). Such a large number of

consistently problematic readings on a very small number of high-stake

feeders also points to the possibility of substantial leakage at the HT level.

Madhya Pradesh

The tariff proposal put up by Madhya Pradesh Electricity Board (for FY

2001-02) before the SERC clearly mentions that, as per the study carried out

by M/s Descon Consultants, commercial losses attributed to the HT industries

is estimated at 5.4% (of energy available for sale at the bus-bar).

Unfortunately, no details about the methodology or sampling used in this

study were available. Table 1 below is reproduced from the MPEB tariff

application.

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Table 16: Estimated Break-up of T& D losses in M.P

Energy Input (MU) 27,000

T&D Losses (as the percentage of Generation) 43.2%

Technical Losses 15.3%

Total Commercial Losses 27.9%

HT Industry 5.4%

LT Industry 6.5%

Household 13.0%

LT Commercial

3.0%

Total Commercial Losses

27.9%

Source: Consultants study as quoted in MPEB Tariff Application (2001 – 02)(MPEB – 2001)

To summarize, the recent data coming out in the regulatory process

demonstrate that it would not be improper to conclude that in most utilities,

revenue loss due to commercial losses at the HT level would be significant.

5. HT Energy Audit: Key Staring Requirement

The above two sections clearly demonstrate that: (i) the state utilities are

unwilling to establish proper metering even at the HT level, and (ii) there is a

strong evidence to indicate that all losses at HT-level may not be technical

and may include substantial commercial losses. This needs to be viewed in

combination with the facts that in most states, (i) HT consumption is in the

range of 20% - 30% of total sales, and (ii) HT sales account for nearly 50% -

60% of the total revenue. If we take into consideration all these facts it is clear

that even a small commercial loss in the HT-section has significant impact on

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revenue of the utilities. With the HT tariff being twice that of the LT tariff and

the number of HT consumers being less than 0.1% of the LT consumers; it is

obvious that the first point of attack has to be the HT sector. As such, the first

priority in the efforts towards T&D loss reduction should be to establish an

effective metering and audit regime at the HT level to curb revenue loss at

this level.

Efforts of reducing commercial losses at the HT level can take different

forms; starting from proper vigilance and inspection by utility staff (and /or

outside agency) to instituting a rigorous energy audit to identify losses in

various feeders. But, depending simply on administrative measures such as

vigilance squads has proved to be ineffective in the current utility setup. More

direct measures, which could hold utility and its staff accountable, need to be

adopted. Rigorous energy audit is one such measure. Such an audit should

aim at establishing the energy balance right from the points of generation /

power purchase to points where energy is transformed to LT level. In

addition, the audit system should be capable of

(i) detecting malpractices on a routine and consistent basis;

(ii) being implemented in a time bound manner; and

(iii) evolving concrete and indisputable performance indicators

for the utility staff

The energy balance can be depicted in the equation form as follows:

Energy Loss (HT level) =Energy generated (net) (A) + Energy Purchased (B)

- Energy Consumed by HT consumers (C) - Energy transformed to LT (i.e.

440 V) (D)

In the above equation, A and B are metered points and these data are readily

available with all utilities. Part D, i.e., energy transformed to LT side is

difficult to measure and may involve sizable investment as well as number of

metering points. For example, in the case of Maharashtra, accurate

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measurement of Part D would imply metering of 180,000 distribution

transformers (DT) on LT side. This implies an investment of around Rs 150

crore (about 1.5% of utility revenue) for metering. In addition to HT energy

audit, this approach will allow us to zoom onto the DT level losses and,

hence, would be far effective in localizing high theft points. But its

implementation - in terms of installation of meters, proper maintenance,

reading, and data analysis in a routine and consistent manner - could take

substantial time. Hence, as an intermediate option, some approximations

could be considered. These are discussed below.

The first such approximation could be to restrict the audit only up to 33 kV

level (i.e., instead of measuring energy transformed to 440 V, energy

transformed to 11 kV or 22 kV should be considered). Since energy fed into

all the 11 / 22 kV feeders is now measured or expected to be measured soon

(as per the MoP’s August 2001 report), calculating such an energy balance up

to 33 kV is simple. It only involves maintenance and reading of all meters on

the 11 / 22 kV feeders (in the substations). In state such as Maharashtra, this

reduces the meter reading points to around 5,500 outgoing feeders and

existing meters of HT consumer. But this would cover over 20% of the total

energy fed into the system and 25-30% of revenue. The 11/22 kV express

feeders, i.e., feeders supplying to only HT consumers, could be readily

brought into this audit, expanding the coverage a little more. In the

subsequent phase, efforts could be made to include all 11 kV or 22 kV feeders

supplying to at least one HT consumer. Tackling these mixed feeders, i.e.,

feeders supplying to HT consumers as well as having DTs (i.e. 11/22 kV to

440 V) could be somewhat tricky. Depending on the configuration of each

such feeder, different options will have to be adopted. Some possible options

would include supplying HT consumers through a separate feeder (as was

being attempted in some states as part of the system improvement program) or

installing check meters for a group of HT consumers. Installing meters on LT

side of DTs could be considered, where the number of DTs on the feeder is

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less. As a last resort, one could install a check meter for each HT consumer on

such mixed feeders. Investment required for such additional metering need

not be a deterrent for its implementation. For example, Maharashtra has

around 10,000 HT consumers, which give revenue of around Rs. 6,000 crores

p.a. Assuming additional metering at all of these 10,000 points (check meters

for each consumer) at a cost of Rs. 50,000 per metering point, the one time

investment would be Rs. 50 crores. This ONE TIME investment would be

less than 0.5% of the utility’s yearly revenue (or 1% of HT revenue). Such

check meters can help identify the problematic consumers / areas, where

difference in check meter and consumer meter readings falls outside the range

+/- 1% or either of the meter reading is unavailable. This can also become a

concrete performance indicator for the staff.

Depending on the state of the HT metering and capabilities of the utility, the

manner and the speed of the action-plan may vary. However, there is no

barrier to achieving the minimum target of ‘Energy Audit’ up to the 33 kV in

a short time of say, one year. This audit should give an energy balance right

from the generation (or power purchase) points up to the HT consumers.

Difference in such audited loss figures and the estimated technical losses

(based on the load-flow study) could be a concrete indicator of commercial

losses.

Such an approach involving tight and complete energy audit at the HT level is

desirable for several reasons discussed below.

Relative Ease of Implementation

As discussed above, effective energy audit at the HT-level requires

installation and reading of only a few thousand meters, unlike the audit of LT

system.

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Low Investment and High Returns

Since HT tariff is significantly higher than LT tariff, reduction in HT

commercial losses would be much more valuable. Such high returns coupled

with the relatively low-levels of investment and managerial inputs required to

institute HT-level energy audit (compared to the LT energy audit or 100%

metering approach), imply quicker and higher benefits. This is essential

considering the current precarious financial situation of utilities. A ’back-of-

the-envelope— calculation for MSEB indicates that HT energy audit can pay

back the investment (of around Rs. 50 Cr.) in just half a year, if theft of only

238 MU (= 0.5% of bus bar energy or about 2% of the HT consumption) is

curbed.

“A No-Regrets” Strategy

Effective metering at the HT level is also essential for implementing ‘Total

Energy Audit’ and theft (identification and) reduction through “100%

Metering approach”. This is because at times meters indicating input energy

to a division / zone are malfunctioning or readings are misreported, resulting

in higher transmission /HT losses and lower losses at division / zone level. To

address this issue it is essential to have equal emphasis on correct

measurement of transmission and HT losses and reduction in the same. Such

HT energy audit is also essential for reforms involving unbundling of utilities

or even for implementing concepts such as profit centers in existing SEBs.

Further, if utility is unable to effectively carry out even the HT energy audit –

which requires much less managerial and administrative efforts (compared to

‘Total Energy Audit’ and ‘100% Metering’ approaches) - then the very

expectation of T&D loss reduction to a reasonable level will need serious

rethinking.

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6. The “100% Metering” Approach: A Long- term Solution

The approaches of “100% Metering” and “Total Energy Audit” are essential

for achieving several objectives such as:

a. tariff regime based on the principle of “pay as per-use”

b. better targeting of subsidy,

c. identification of some of the 11/ 22 kV mixed feeders that have

excessive technical or commercial loss, and, finally

d. establishing accountability up to the level of linesmen of the

utility.

Hence, it is inescapable to carry out the “Total Energy Audit” as well as

‘100% Metering’.

But, it needs to be considered that this requires not only large investments but

also immense efforts involved in installation and regular reading of millions

of meters (in each state) as well as in billing equally large number of

consumers. In the case of millions of “single bulb houses” innovative

approaches such as load limiters and efficient bulbs would be far more

prudent than blanket metering in the medium term.

The second consideration in making effective use of “100% Metering” relates

to the billing systems of SEBs. Many utilities are yet to install the system of

computerized billing and systematic numbering of each consumer (linking the

consumer to a pole / DT or a feeder). Further, well-designed software to

capture and analyse these data will have to be put in place and used by a large

number of sub division level staff!

Another aspect relates to integrity of the audit. Unless the billed energy is

traced back to the supplied energy up to the point at which energy is fed into

the system, the utility of the whole exercise could be greatly reduced. The

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whole exercise can be rendered ineffective by tampering (or making

dysfunctional or not reading) just a few key meters.

These will certainly act as major hurdles in implementing and effective use of

“100% Metering” towards the goal of complete LT level energy audit.

Before we commit to ‘100% Metering’ as the sole answer, it is worth doing a

reality check. Metering and billing performance of utilities is not very

encouraging even in the case of categories of customers that already fall in the

‘100% metered’ bracket (e.g., domestic, commercial, and industrial). In

Orissa, most of the LT consumption is not metered. In UP, consumption of

44% of metered consumers (that include domestic, commercial, and even

small industrial consumers) is “assessed” and not measured. During the first

tariff hearing of MSEB, it was revealed that about half of the bills issued to

residential and commercial consumers were not based of metered

consumption despite these consumers had been metered since the time of

connection.

Considering these factors, despite large investment and immense efforts,

approaches of ‘100% Metering’ and “Total Energy Audit” are unlikely to

yield significant results in most states within a time frame of three to five

years. Hence, we cannot ignore the HT audit and it has to be treated as the

starting point for proper identification of high loss area, for curbing theft and

more importantly the revenue loss.

Conclusion

The emphasis by SERCs and the Ministry of Power on reduction of excessive

T&D losses is a welcome development. Considering that many power utilities

are almost bankrupt, it is essential to give higher priority to measures that can

lead to increased revenue within a short time with limited investments, and

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with limited managerial efforts. This understanding coupled with the recent

evidence of poor HT-level metering and possibilities of significant

commercial losses at the HT level, necessitates that the approach of stringent

HT-level energy audit be made the foremost priority. This crucial as well as

urgent measure should not be put on the backburner in our zeal to ensure

“100% Metering” and “Total Energy Audit” at the LT level.

Many SERCs have directed utilities to undertake HT energy audit in

successive tariff orders. Considering the importance and relative ease of HT-

level energy audit, the SERCs need to be far stricter in dealing with the

failures of utilities in complying with their directives in this regard. This is

essential for maintaining the sanctity of the directives by SERCs. For

example, the SERCs should direct utilities to institute effective HT-level

energy audit within a reasonable period and should reject any tariff proposal

after that period, if it is not accompanied by proper results of the HT-level

energy audit. Unless the SERCs adopt such unyielding stand on

implementation of such crucial, urgent, and relatively ‘easy-to-implement’

measures, the entire regulatory process would soon be rendered ineffective.

On the other hand, such unyielding stand on the part of SERCs would also

create pressure on the utility’s top brass to make those responsible for HT

energy audit more accountable. SERCs should also direct utilities to publish

results of such energy audit (along with names of concerned officers) through

newspapers as well as on the Internet so as to facilitate public scrutiny of

utility’s performance.

In order to facilitate HT energy audit and to overcome the financial

difficulties associated with procurement of meters, the SERCs may choose to

charge a special component in tariff, which should be devoted exclusively to

meeting expenses relating to the HT-level energy audit. Consumers should be

willing to share this small additional burden (of the order of 1 or 2 paise per

unit) to ensure that utility is made accountable. Such an approach would also

170

help in ensuring more stringent public scrutiny of performance of utilities on

this account.

Simply carrying out stringent HT level energy audit and curbing HT theft

would, by no means, be sufficient to make utilities financially viable.

Reduction of high technical losses, LT level theft, and other efficiency

improvement measures are also essential. But curbing HT theft with iron hand

would, on one hand, give the utilities much needed cash and, on the other

hand, would give a clear signal to corrupt utility staff and consumers that the

party is over. Such a signal is also critical for the success of measures such as

“Total Energy Audit” and “100% metering”.

171

Reforms and Restructuring Initiatives in Orissa’s Power Sector In 1994, the government of Orissa initiated power sector reforms and its

restructuring. The reform programme resulted in the vertical unbundling of

the state owned integrated utility, corporatisation of resultant entities and

constitution of an autonomous regulatory commission for power sector

regulation in the state. One of the key features of the reform programme

was the privatization of distribution activity. To make the process successful

and obtain more revenues, there was need for the distribution entities to

change the existing culture and approach to management. The state

government undertook a process of organizational strengthening to develop

appropriate organizational structure, systems and business process suitable

to the new environment.

Encouraged by the Government of India, assisted by the World Bank, and

supported with grants from the Government of U.K (DFID), Orissa took the

initiatives and earned the reputation of being the first state to reform its

electricity industry. The Orissa Electricity Reform Act, setting out the basic

framework of the reform, enacted in 1995 came in to force from 1 April 1996.

The principal objectives of the reform, as set out in the preamble to the Act

and the policy papers of the Government of Orissa, were the following:

a. Restructuring of the electricity industry for rationalization of

generation, transmission, distribution and supply of electricity.

b. Development of the industry in an efficient, economic and competitive

manner.

c. To provide for avenues for participation in the industry of private

entrepreneurs, attract private investment and reduce the need for

government funding of the electricity sector.

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d. To improve the quality of the service to the consumer.

e. To enhance operational efficiency and reduce losses.

f. To provide for a transport mechanism for development and regulation

of the industry, including tariff fixation and dispute settlement, through

an independent statutory body, the Orissa Electricity Regulatory

Commission (OERC).

g. To contribute to the economic growth of the state by ensuring superior

electricity supply, and

h. To create opportunities for increasingly rewarding employment for

technical personnel and provide a stable environment for career

development in the electricity sector.

Conceptualization of the reform and road map for its implementation had

been drawn up after elaborate exercise in association with the World Bank

and with active involvement of a large number of consultants including

several foreign consulting firms of high international repute.

FIRST PHASE OF REFORM:

All the major steps in the restructuring process have since been taken as

envisaged under the reform scheme:

• OSEB was restructured and corporatised in to Grid Corporation of

Orissa (GRIDCO) and Orissa Hydro Power Corporation (OHPC) in

April 1996.

• The Orissa Electricity Regulatory Commission (OERC) was

established in August 1996.

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• Orissa Power Generation Corporation (OPGC) was privatized with

divestment of 49% stake and transfer of management control to a

private operator, AES in January 1999.

• Four distribution companies (DISTCOs), incorporated as wholly

owned subsidiaries of GRIDCO, were privatized with transfer of 51%

stake to private operators: three of these, namely, NESCO, WESCO

and SOUTHCO were acquired by BSES in April 1999 and the fourth,

viz. CESCO by AES in September 1999.

In brief we can summarize that power sector reform comprised of

Restructuring OSEB, Privatization, Competition, Regulation and above all

reforms in tariff structure.

Since the existing legal provisions were not adequate to provide necessary

managerial and financial autonomy to the power sector, it was necessary to

draft the Orissa Electricity Reform Bill, 1995 with provision to establish an

independent and transparent regulatory commission and thereby attract

private investment in to the state power sector. The assets and personnel were

also transferred to the newly created entities such as the GRIDCO and OHPC

with effect from the first of April 1996 on provisional basis. The transfer

became absolute with effect from 1st April 1997.

GRIDCO disinvested 51% of its equity holding to private investors with

strong financial standing and technical capabilities. 10% of the equity has

been reserved for the employees of GRIDCO- which would entitle them to

direct monetary and welfare benefits. GRIDCO retains 39% of the holdings in

the DISTCOs.

174

Chart 6: Relationship between different party

Background of OSEB Established in 1961, OSEB was the main body responsible for power sector

development in the state. OSEB was vested with the responsibility of public

power supply in the entire state as well as for related state level regulation.

OSEB obtained the required power for distribution either from its own

generating stations or by purchasing from other generating utilities. By using

its transmission and distribution network, it applied power to the end

consumers.

OSEB was owned by the Government of Orissa and was governed by the

provisions of The Electricity (Supply) Act. 1948. The 1948 Act explicitly

required the SEBs to operate and adjust their tariffs to achieve a minimum

return after interest of 3 percent on net fixed assets in operation. According to

the provisions of Electricity (Supply) Act, 1948, state governments were

required to provide subsidies to help the SEBs meet their minimum return

requirements by compensating for the low tariffs charged for residential and

agricultural consumers.

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Performance of OSEB

The performance of OSEB in terms of Plant Load Factor (PLF) and

Transmission & Distribution losses had been quite poor vis a vis other SEBs

during the period 1991-94. During this period, Orissa also had a considerable

power deficit which was estimated to be in excess of 10 percent, higher than

the all-India average of 8 percent.

The Transmission and Distribution losses though stated to be around 24

percent by OSEB were reported to be much higher. A clear indication of large

transmission and distribution losses was made in the Annual Administration

Report of the GRIDCO which listed such losses as high as 49.47%.

In 1993-94, the ratio of customers served to the employees of OSEB was 29,

whereas the all India average was around 80 (Comparison of performance of

Electricity Boards and Electricity payments, Planning Commission,

Government of India, 1994). The billing and collection of OSEB had been

poor because a large portion of the billing was not done on the basis metre

reading but on average consumption or on load factors, which resulted in

lower collection revenues. Figures available for 1996-97 indicated that only

12.19% of the total bills were based on metre reading.

Lack of appropriate controls and poor accounting of sales revenues had

affected the revenue collection. Figures available for 1998 indicated that in

some of the revenue divisions, the percentage of billings collected was as low

as 17%. Unmetered supply to a large number of consumers and theft of power

resulted in non-technical losses being as high as 20-25 per cent. (There are two types of power losses during transmission and distribution: technical and non-

technical losses. Technical loss is the energy lost in the wires and equipment in a distribution

system for technical reasons like resistance. Non-technical loss or commercial loss occurs due to

theft, non-metering or defective / tampered metering of consumers, and inefficient billing and

revenue collection systems)

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In spite of an annual average growth of about 19% in sales revenue, OSEB

had not been able to earn the statutory rate of return of 3 percent on net fixed

assets without subsidy from the Government of Orissa because of its very low

level of tariffs. In spite of the sales revenue not being able to meet the

operating costs, there was no tariff increase from 1990 to 1992.

Table 17: Achievement of OSEB during 35 years Sl. No.

Area of Achievement

1961-62

1974-75 1984-85

1994-95 1995-96 1999-2000

1. Installed Capacity(MW)

9.897 547.675 1134 1731.93 1731.93 2498.88

2. Transmission & Distribution Lines(KM)

2839.67

33945.21

83414 116715 118286 120625

3. Total Energy Input(MU)

641.43 2335.07 4348 7851 9244.93 11130

4. Energy Sold (MU)

556.44 1995.12 3566 6471.14 4560.36 6286.49

5. % Loss of Energy Sold

13.2 14.5 17.9 17.6 50.4 43.52

6. Energy Billed(MU)

- - - 4536.33 4560.36 6286.49

7. % Loss to Energy Billed

- - - 42.22 50.4 43.52

8. Revenue Earned (Cr.)

2.23 23.31 116.09 725.11 912.14 1547

9. Consumers Served (no.s)

31013 234977 716706

1230354

1273844

1600551

10. Villages Electrified(No.s)

118 11525 23762 33131 32088 35190

11. Assets in Use(Cr.)

4.91 133 498.3 1073.14 1022.85 -

12. Employees (No.s)

4737 18224 33000 34450 34732 28309

13. Per capita Consumption (Kwh/Yr.)

31.8 73.3 137 248 292.5 352

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Orissa Achievement in Distribution Sector Second Phase of Reform Privatization of Distribution Functions:

In pursuant to the Orissa Electricity Reform (Transfer of Assets, liabilities,

proceedings & personnel of GRIDCO to distribution companies) Rules, 1998,

the government of Orissa transferred the distribution assets and properties

along with personnel of GRIDCO to 4 distribution companies namely

CESCO, NESCO, WESCO, and SOUTHCO continued to function as

affiliates of GRIDCO up to 31.03.1999 and thereafter functioned under the

distribution and retail supply license obtained from OERC.

Objectives of Privatization of Distribution Function:

A. Operational Improvements :

(i) Improve quality of service to consumers

(ii) Improve operational efficiencies and reduce losses.

B. Financial Benefits :

(i) Attract private investment to the distribution business

(ii) Reduce the need for government funding of the electricity

sector

(iii) Contribute to increased economic growth in Orissa.

C. Employee Considerations :

(i) Create opportunities for secure and increasingly rewarding

employment for the qualified personnel

(ii) Provide a stable environment for employees

D. Sale of all 4 Zones to promote competition

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In keeping with the objectives of power sector reform and the commitments

given to the World Bank by the state government, the distribution function

was required to be privatized. After considerations of various options

available for privatization, the corporation decided to adopt the best mode of

Joint sector/ Joint venture route. The sequence agreed was that the four

distribution zones which were functioning under the corporation will be

converted into four distribution companies as its wholly owned subsidiary.

The privatization process was accomplished in three stages e.g. Qualification

of companies/consortia, RFP and Lodgement of bids and negotiation and

completion. 51 companies/consortia initially participated in the ICB but 13 of

them furnishing SOQs. 11 companies were pre-qualified by GRIDCO board,

out of which 4 companies did not participate in the bidding process because

of reasons e.g. Asian Economic Crisis, Pokhran-II blast and unviable and

small businesses and regulatory risks. 4 more companies did not participate in

the bidding process. Out of the remaining bidders, the following 03 bidders

were found to be technically qualified like BSES, Singaporepower-Grasim

and TEC-Viridian. BSES was selected for WESCO, NESCO and SOUTHCO

and the management was handed over with effect from 01.04.99. As TEC-

Viridian failed to honour their offer, the earnest money guarantee of Rupees 5

crores was invoked. Dispute raised by TEC-Viridian is pending in arbitration.

AES-Jyoti structure, the pre-qualified bidder was selected for CESCO through

a process of negotiation and the management was handed over with effect

from 01.09.99. Thus through a process of international competitive bidding,

GRIDCO offered 51% stake to private sector investors keeping a share

holding of 39% with it and 10% share for Employees Welfare Trust.

It may be mentioned here that no asset sale has taken place. Assets have been

assigned to respective companies. Only the business has been sold with a

179

premium although all the 4(Four) companies are loss making and bore a part

of the loans and liabilities.

The new structure of the electricity sector in Orissa is as follows:

1. There are independent generation sources like NTPC, OHPC, OPGC,

IPPs and CPPs.

2. GRIDCO purchases power under PPAs from the independent

generators and provides bulk supplies to privatized distribution

companies at a bulk supply price. This means GRIDCO acts as a

Transmission Company between the generators and the distribution

companies.

3. Privatized Distribution Companies have come into existence viz.

WESCO, NESCO, SOUTHCO and CESCO. These privatized

distribution companies cater to the needs of customers.

RESTRUCTURING OF GRIDCO

GRIDCO presently undertakes –

1. The Transmission and Bulk supply activities in the state of Orissa.

2. Sale of energy outside the state of Orissa.

3. The SLD (State Load Despatch) Functions.

Under the provisions of the Electricity Act, 2003, trading in electricity has

been recognised as a distinct activity which can only be undertaken with a

license to be granted by the appropriate commission. Trading has been

defined under the new act as purchase of electricity for resale thereof and,

therefore, the bulk supply of the electricity becomes a licensed activity being

180

covered under trading. Transmission of electricity has also been recognised as

an independent activity to be carried on under a license from the appropriate

commission.

GRIDCO in addition to its transmission functions as a State transmission

Utility is also operating as SLDC (State Load Despatch Centre). Under the

Electricity Act, 2003, the SLDC shall be operated by a govt. company or

under any state act, as may be notified by the respective state government.

Provided that until a Government Company or any authority or corporation is

notified by the state government, GRIDCO being the State Transmission

Utility (STU), shall operate as SLDC.

In view of the aforesaid statutory requirement, it has become necessary to

take steps for separating the Trading Functions of the GRIDCO from the

Transmission and SLDC functions.

The matter is now under consideration and the following course of action is

being contemplated.

1. GRIDCO will continue to undertake bulk supply and trading functions

and will transfer the transmission functions together with the SLDC

and State Transmission Utility Functions to another new Company

(Transferee Company).

2. A public limited company under the companies act, 1956 as a wholly

owned undertaking of state government shall be incorporated for

vesting and transfer or transmission/ STU and SLDC undertaking of

GRIDCO along with its personnel.

3. There shall be a transfer of Transmission and SLDC functions of

GRIDCO for vesting with the newly incorporated company. The

181

transmission and SLDC undertakings shall comprise all properties,

rights, liabilities, etc., pertaining to Transmission/STU function and

SLDC functions along with personnel and the transfer shall be affected

through a Statutory Transfer Scheme to be notified by Govt. of Orissa

u/s 39 read with section 131 of the Electricity Act, 2003. The said

transfer Scheme shall be effective from 01.04.2004 so that the newly

incorporated (Transferee Company) starts functioning w.e.f

01.04.2004.

4. State Govt. is to issue a notification declaring the new company

(Transferee Company) as the State Transmission utility (in super

session of earlier of earlier notification declaring GRIDCO as STU),

which may form a part of Transfer Scheme to be issued by the state

government and the transfer scheme shall provide that the

Transmission company as the State Transmission utility (STU) will

also operate the State Load Despatch Centre until further orders of the

state government.

5. The new company (Transferee Company) to be incorporated may be

named as any one of the following subjects to the same being available

from the Registrar of Companies, India:

(A) Power Transmission Corporation of India Ltd. (TRANSCO)

(B) Orissa Power Transmission Corporation Ltd. (OPTCL)*

(C) Power Grid Corporation of Orissa Ltd. (PGCOL)

6. GRIDCO shall obtain a license from CERC for interstate trading of

power on or before 9th. June 2004. GRIDCO shall continue with the

business of bulk supply/inter-state trading with its license obtained

from OERC but shall apply to OERC for deletion of transmission

function from license.

182

Chart 7: GRIDCO STRUCTURE

183

Sequence of Events of Reforms The blueprint and milestones for the reforms were drawn up via the World

Bank’s Staff Appraisal Report (SAR), and the reform experiment was ready

by 1995. The process was as follows:

1993 Chief Minister announces power reforms plans.

1994 Planning for reforms continues.

1995 Regulatory Reforms Bill passes in the state legislature.

1996 Orissa Electricity Reform Act took effect on April 1, 1996. OSEB was

divided into the Orissa Hydro Power Corporation (OHPC) for all hydel

capacity and GRIDCO. GRIDCO inherited the transmission and distribution

infrastructure, as well as the liabilities of the SEB. The already existing Orissa

Power Generation Corporation (for thermal power) continued, but future

generation capacity was to come from IPPs. Orissa Electricity Regulatory

Commission (OERC) was also established.

No budgetary support was envisaged for any of the bodies, except the

regulatory body. But, to help out the enterprises, their accumulated losses

were to be written off, their assets revalued, and their liabilities readjusted.

Based on the recommendations of various consultants, a depreciated

replacement model was chosen to revalue the assets of OHPC and GRIDCO.

The assets of GRIDCO increased from a book value of Rs. 1,183 Crore to Rs.

2,395.8crore. There were also various liabilities, including to NTPC, and

these were converted to a term loan of Rs. 1,148.9crore, plus some significant

short-term liabilities (Mahalingam 1997). The total capacity was 2,120 MW

within these units.

184

1997 OERC issues first tariff orders.

1998 4 Distribution zones were established as separate corporations (still

PSUs) out of GRIDCO. Even then, GRIDCO remained the single-buyer of

power to sell to the 4 DISTCOs. 1999 The 4 DISTCOs were also privatized,

with a release of 51% of the equity in each held by GRIDCO. 39% would

remain with the state government, and 10% would be held by employees. The

central zone went to AES Transpower, the US multinational, and the other

zones went to BSES. Workforce allocation and severance were long, drawn

out processes according to most reports. To facilitate the sale, GRIDCO

accepts deferred payments, which affects it cash flow position significantly

later on. Orissa Government divests 49% of its stake in OPGC, via

competitive bidding. AES wins with a Rs. 6.03 billion bid, giving it operating

control of 2x 210 MW thermal plants in Ib Valley. These plants were

commissioned in 1994 and 1996, at an investment of Rs. 11.35 billion (Iyer

2000). Not the entire bid was towards assets; fresh capital was also invested

(8%, equal to Rs. 1.03 billion).

2000 GRIDCO’s financials worsen, and debt levels of the companies rise.

2001 Government constitutes Kanungo Committee to examine the reforms

process, AES withdraws from the central zone distribution. Government

appoints an administrator for this zone. His appointment is stayed by the

courts. BSES states it is not interested in taking up the central zone.

2002 The performance of 3 of the 4 zones worsens compared to the previous

year (Southern, with BSES, is the exception).

That reforms are not straightforward, nor can private operator easily succeed

is illustrated by the attempt in September 1996 to hand over one section of

distribution (the central zone, which included cities like Cuttack and

185

Bhubaneswar) to BSES for operation, under a management contract. After the

first 6 month review found negative performance, the management contract

was terminated in April 1997. In response, BSES stated it was not given

enough time to effect change, disputed the baseline numbers, and said that it

never really had control over the staff (Mahalingam 1997), a concern for any

reform mechanism based on outsourcing.

Also, AES came into distribution somewhat reluctantly (Mahalingam 1998).

It was originally in the state as a power generator (IPP), with the 500 MW

(250 x 2) Ib Valley Project. However, during the privatization process, BSES

was the only eligible bidder for the 4 zones, after Tatas withdrew from the

central zone (Prayas 2001). But, to ensure they didn’t get all the zones, AES

was persuaded to take over the central zone.

BENEFITS OF REFORMS

1. TTPS (Talcher Thermal power Station) after taken over by NTPC is

now operating at a PLF of 75.1% whereas from its inception it never

operated beyond 30%.

2. OPGC being exclusively in charge of Thermal Generation has been

consistently maintaining high PLF of 70 to 80% - a performance level

comparable to NTPC.

3. Disinvestment of 49% of Government share has unlocked a substantial

amount of funds which could be utilized for power development.

4. OHPC being exclusively in charge of Hydro Power Stations could give

undivided attention and bring back the two units at Burla to operation

after renovation.

186

5. Each year Government was to give a subsidy of Rs. 340 Crore. This

has been stopped since 01.04.96.

6. OHPC & OPGC, which are exclusively looking after hydro and

thermal generation of power respectively, are now profit making

corporations of the state.

7. In a sharp turn around now Power Sector is not loss making (See

table).

Table 18: Accounting P\L

1996-97 1997-98 1998-99 1999-2000

2000-01 2002-03

OPGC 104.6 66.15 112.8 124.39 109.88 132.22 OHPC 69.85 77.79 55.21 50.38 -27.44 -3.89 GRIDCO -294.99 -319.11 -578.61 13.73 -86.44 22.14 Total -120.55 -175.17 -410.6 188.5 -3.73 150.47

Table 19: Cash P\L

1996-97 1997-98 1998-99 1999-2000

2000-01 2002-03

OPGC 144.96 147.31 195.68 208.97 194.68 215.91 OHPC 114.26 122.06 99.93 100.19 65.92 92.69 GRIDCO -162.03 -177.45 -428.7 86.85 -4.91 112.44 TOTAL 97.18 91.92 -133.09 396.01 255.69 421.04 Though the above mentioned outcomes are some positive aspects of the reforms but all was not well in the years that followed and some of the negative outcomes are discussed in the following paragraph. The reforms were supposed to improve the power position in Orissa, but peak

shortages continue. The finances of the companies have worsened to some

extent, and the losses continue to mount (financial as well as technical).

GRIDCO failed to pay generators what it owes, citing failure of receiving

payments from the DISTCOs. Had they received their money, the generators

187

(OHPC and OPGC) have a book profit of Rs. 768 crores between April 1,

1996 and March 31, 2001 (OERC 2002).

The WB-SAR (Staff Appraisal Report) based report called for a number of

milestones, details on which can be found in Prayas (2001). Most of these

were based on structural changes, like setting up the distribution zones,

having OERC issue tariff orders, etc. However, some of these had negative

operational effects as well. The goal of 16% return for OHPC along with its

valuation hiked the costs to GRIDCO significantly, by hundreds of percent.

This is an indication that reforms process, as profitable companies come up

along the power sector (generation, transmission, and distribution), this will

raise the average cost of power compared to today’s loss-making utility.

One casualty of the reforms process was rural electrification. Private

companies were not interested in such loss-making operations. The

agricultural demand for power went down from a low 6% in 1992-93 to a

very low 3% in 1999-00 (Kanungo Committee 2001). But yet, the finances

didn’t improve. This highlights the importance of mechanisms to ensure

rural/underserved areas are catered to. Either specific targets must be set and

met, or an outside entity should be entrusted with such a role. Rural

cooperatives might be one solution for such consumers. The noted

environmentalist Ashok Khosla points out that if communities treat electricity

as a shared resource, they would manage it better, as they have done

historically for things like a shared water supply (personal communication).

What Went Wrong

The main problem with the operations of the sector was relating to cash flows.

OERC limited the increase in tariffs (citing that not all costs could just be

passed on to the consumers – e.g., for bad performance – unlike the pre-

reform days). This created losses for the DISTCOs, who also had deferred

188

payment agreements with GRIDCO. GRIDCO, owned by the Govt. of Orissa,

was caught between the increasingly expensive generators and non-paying

DISTCOs, who were unable to improve performance as expected. While the

exact numbers have varied over time, some details are as follows (Prayas

2001): GRIDCO was owed over 7.7 billion rupees by the 4 DISTCOs as of

March 31, 2000. Of this, CESCO (the central zone operated and majority-

owned by AES) owed Rs. 1.6 billion. But, GRIDCO owed OPGC, of which

AES owned 49%, some Rs. 1.8 billion. AES shut down a power plant for a

week in protest, and the crisis escalated with the Govt. threatening prison time

for its officers (under the Essential Services Act). The compromise solution

involved the government promising to pay its dues in 15 days.

After the reforms, GRIDCO’s and DISTCOs finances went down because of a

number of factors (Prayas 2001; OERC 2002):

• The bulk of the liabilities went to GRIDCO, Rs. 16 billion vs. 6 billion for

all the DISTCOMs.

• Assets of GRIDCO were revalued upwards, to help match the increase in

liabilities. This had operating implications, like the increase in depreciation

costs.

• OHPC’s tariffs were increased to meet the 16% returns. Overnight, the tariff

went from Rs. 0.1 to Rs 0.49/kWh in 1996. Even central station’s power was

expensive, and GRIDCO had to off take such power.

• There were unrealistic T&D losses estimated during the unbundling process.

This stresses the importance of accurate baseline information, and realistic

performance targets. The forecast for T&D reduction from 39.5% in 1996-97

to 22.7% 2000-01 wasn’t achieved. Even the initial assessment of 39.5% for

1996- 97 was grossly incorrect. A later audit showed this to be 49.4%.

• Tariff increases were lower than in the WB-SAR.

189

• There was no budgetary support via subsidies.

• The growth of load, especially profitable load, did not materialize. The WB-

SAR called for 7,009 million kWh for railways plus industrial high tension

(bulk) supply, while the actual sale in 2000-01 was 2,760 million kWh. This

affected not only the cross-subsidy potential, but the T&D losses as well.

• Poor collection rates from consumers. DISTCOs achieved only 75 and 76%

collection in 1999-2000 and 2000-01, respectively.

In addition to these issues, we find several other factors at play. Not enough

was invested in this sector towards the reforms. Less than half the money just

from World Bank was spent, making the total fraction utilized based on the

billion dollar estimate even lower (Kanungo Committee 2001). Critics will

point out that a significant fraction went to consultants, 306.422 crores (but

the bulk of this came from DFID funds, and none came from consumers).

There was also a cyclone that hit just after privatization, before proper

insurance was in place, causing not only a financial loss, but a major

operational challenge.

The AES episode created a lot of controversy, with their reporting

Government interference and lack of law and order, but the Kanungo

Committee Report (2001) counters a lot of difficulties were caused by AES

practices. They created a new management cadre, which caused a lot of

resentment within CESCO, the Central DISTCOs. In addition, they came in to

CESCO expecting to take up an additional 2% in OPGC, giving them 51%.

When that didn’t materialize, that triggered their desire to sell their state in

CESCO in 2001.

190

However, the biggest reasons for the poor performance appear to be the false

assumptions and expectations of the players, and the limited support provided

by the government, either for subsidies or to the companies who had liquidity

issues in addition to solvency issues. Money coming in from outside sources

was often diverted to state budget needs, and there remained significant

institutional lethargy and morass in the sector. The government failed to pay

its own dues for power, some Rs. 1.5 billion.

Some of the lessons from the Orissa experience, other than the obvious ones

include (IDFC 2000):

• Incomplete separation of transmission and distribution can cause problems.

• Regulators should give a clear picture of their tariff philosophy, rate base,

valuation methods, likely profile of prices and expected performance levels.

• There should be a structured, time-bound financial support mechanism, with

a fixed schedule for tapering off coupled with improvements in operating

parameters and collection.

• The single buyer model is necessarily not the best, and the Transco might be

better as just a wires company.

• Determining who gets priority claims over revenues is important. Do not

escrow the revenues from the distribution zones for meeting TRANSCO

needs, like was done in Orissa.

• Don’t tinker with valuations, especially just before privatization. This can

have a serious impact on tariffs, as Schedule VI of the Supply Act 1948 is

based on assets (and newer methods allow for 16% returns on equity).

191

Transfer of Assets

The restructuring was done in two steps through the instrumentality of

transfer scheme framed under the Orissa Electricity Reform Act, 1995. Under

the first transfer scheme (effective from April 1, 1996) the assets, liabilities,

proceedings and personnel of erstwhile OSEB were transferred to OHPC (for

hydel generation) and GRIDCO (Transmission & Distribution). The second

transfer scheme (effective from November, 1998) further transferred the

distribution related assets, liabilities, proceedings and personnel of GRIDCO

to four wholly owned companies of GRIDCO.

Table 20: Details of Revaluation

Details of Revaluation done in Transfer Scheme dated April 1, 1996

Rs. in Crores

Book Value of T&D Asset 1103.2 Interest and expense capitalised 97.5 Total 1201.0 Uplift in Value of Assets 1120.0 Total 2320.7 Depreciation 363.0 Net Fixed Assets of GRIDCO as on April 1, 1996

1957.7

Total Revaluation Uplift In Assets 1120.0 Further Adjustment 74.0 Total 1194.0 Adjustment Subsidy due to OSEB 301.2 Electricity charges receivable from Government

39.2

Reduction in O&M stock 50.6 Total (A) 391.0 Fresh Equity to State Govt. 253.0 Zero Coupon Bond to State Govt. 400.0 Bonds issued to Pension Fund 150.0 Total (B) 803.0 Total (A+B) 1194.0

192

RESTRUCTURING EXERCISE INVOLVED CERTAIN MEASURES,

WHICH CAST A HEAVY STRAIN ON THE FINANCES OF GRIDCO

Under the transfer Scheme of April’96, the state government took over the

Transmission and Distribution assets of OSEB (book value plus capitalized

expenses and interest at 1200 Cr.) and reinvested them in GRIDCO after

upvaluing by an additional Rs. 1194 cr. (additional 134%). Against this

upvalued amount of 1194 Cr, the state Govt. adjusted subsidies and electricity

charges payable to OSEB/GRIDCO totalling Rs.340 Cr. In addition GRIDCO

issued Rs. 253 Cr. Worth of shares and Rs. 400 Cr. Worth zero coupon bonds

to the state govt. This left GRIDCO with a serious cash shortage right from

day one and compelled it to default it to generating companies and other

suppliers. In addition Rs. 1146 Cr. of loan and liabilities were also assigned to

GRIDCO.

The upvaluation exercise was prompted by considerations including the need

to have a capital base capable of absorbing substantial debt funds needed for

the up gradation of the T&D system and the requirement of having a self

financing ratio of 20% and an adequate debt-equity ratio as per World Bank

conditions. It was also felt that the assets should be valued on the basis of

their business potential and replacement value, not their book value. The

revaluation exercise also enabled the cash strapped state govt. to “Adjust”

dues totalling Rs. 340 Cr. Payable to OSEB/GRIDCO against the

upvalued amount.

The impact of revaluation on the distribution companies has been lower than

that to GRIDCO as they were allocated only project specific liabilities

totalling Rs. 630 Cr. for all four distribution companies put together, while

GRIDCO retained in their books liabilities (including accumulated losses)

totalling about Rs. 1950 Cr. While the assets were upvalued, there was no

such upvaluation of the liabilities. Besides, as stated earlier, the distribution

193

companies were assigned only project related liabilities. The only component

of asset upvaluation which has a bearing on tariff depreciation, which stood at

Rs. 81.69 Cr. in FY96 on the eve of the upvaluation and was pegged at Rs.

128.02 Cr. for FY98 by OERC in their tariff order effective from April 1,

1997.

The difference of Rs. 46.33 Cr. (Rs. 128.02 Cr. – Rs. 81.69 Cr.) in the

depreciation (which also included depreciation of assets created during FY97)

formed only 3.2% of GRIDCO’s total revenue requirements of Rs. 1451 Cr.

allowed by OERC. Hence the impact of upvaluation on distribution tariff has

been estimated to be only about 2.5%. Further, it must be emphasized that it is

not the upvaluation exercise per-se that resulted in GRIDCO’s cash crunch;

the cause is rather the “adjustment” of the totality of its receivables from the

state government (about Rs. 340 Cr.) right from inception.

Table 21: Debt Equity Comparison Rs. In lakhs

As on

1.4.1996 1.4.1997 1.4.1998 1.4.1999 1.4.2000 1.4.2001 1.4.2002 1.4.2003

Audited Audited Audited Audited Audited Audited Provisional Provisional Equity

32620 34369 38423 45795 48786 48817 49106 49298

Debt

122145 127488 146068 240252 255477 291736 354990 420793

Ratio*

3.74 3.71 3.80 5.25 5.24 5.98 7.23 8.54

Equity

32620 34369 38423 45795 48786 48817 49106 49298

Power Purchase Liability

37,057

60,235

89,967

75,937

1,06,505

1,04,693

78,809

89,152

Power Bills

159202 187723 236035 316188 361982 396429 433799 509945

Ratio*

4.88 5.46 6.14 6.90 7.42 8.12 8.83 10.34

*- Debt Equity Ratio.

Table 22: PROFIT / (LOSS) COMPARISON OVER THE YEARS Rs. in Lakhs

1991-92

1992-93

1993-94

1994-95

1995-96

1996-97

1997-98

1998-99

1999-00

2000-01

2001-02

2002-03

Audited Audited Audited Audited Audited R Audited Audited Audited Audited Audited Provisional Provisional

Profit/ (LOSS) After subsidy

2577

2594

2998

2490

2694

E

(29,499)

(31,912)

(57,862)

(1,373)

(8,524)

2,214

(67,622)

F Revenue subsidy Received

7627

11100

22603

16098

25762

O

1138

531

529

0

0

0

0

R Profit/ (LOSS) before subsidy

(5050)

(8506)

(19605)

(13608)

(23068)

M

(30637)

(32443)

(58391)

1373

(8524)

2214

(67622)

Note: Till FY-1995-96 the performance is of erstwhile OSEB and subsequent years of GRIDCO. FY 1996-97 to 1998-99 includes performance of Transmission and distribution business and FY 1999-00 onwards include only Transmission business after privatization of distribution business. The huge loss in 2002-03 is due the unprecedented hydrology failure and consequent additional burden towards purchase of high cost EREB thermal power.

Table 23: DETAILS OF LOANS Rs. In

lakhs As on 1.4.1996 1.4.1997 1.4.1998 1.4.1999 1.4.2000 1.4.2001 1.4.2002 1.4.2 Govt. Loans

State govt. cash loan

200

200

15371

16871

16871

16871

1687

Central govt.

1126

1126

1126

1126

1126

1126

1126

1126

Zero coupon Bonds

40000

40000

40000

40000

40000

40000

40000

4000

IBRD 0 3363 8572 14913 38111 30992 3876Sub-Total 41126 41326 44688 65069 72910 96108 88989 9676Financial Institutions

LIC 14356 14066 14066 14066 14066 14066 14066 1406REC 25018 27070 29559 36767 42877 42784 41099 3691PFC/ADB 13680 19460 21570 26696 30816 31899 30092 4354Sub-Total 53055 60596 65195 77529 87759 88749 85257 9452Bonds & others

Pension Fund Bonds

15000 15000 15000 15000 15000 15000 15000 1500

Public Bonds

10991 8564 6584 5202 4377 3854 3476 2403

Power Bonds/loan syndication

-

-

10948

66756

66756

77637

46256

9755

GoO Bonds to NTPC

- - - - - - 110288 1102

Others (ICICI, SPA etc.)

1973

2002

3653

10696

8675

10388

5724

4260

Sub Total 27964 25566 36185 97654 94808 106879 180744 2295Total 122145 127488 146068 240252 255477 291736 354990 4207The Loan outstanding figure given above does not include the overdue interest. The IBRD loan has been considered as 70% loan and 30% grants from FY 2001-02 onwards.

196

Table 24: STATEMENT OF POWER PURCHASE, SALE, T& D LOSS BILLING COLLECTION ETC YEAR Energy

Purchase(MU)

Energy Sale (MU)

% of T&D Loss

Cost of power (Rs. Cr.)

Amount Billed (Rs. Cr.)

Amount Collected(Rs Cr.)

Collection as % of Billing

1995-96 (T&D)

9244.93 4560.36 50.67% 652.61 908.27 821.53 90.45%

1996-97 (T&D)

9650.00 5088.94 47.26% 982.71 1145.95 963.26 84.06%

1997-98 (T&D)

10324.30 5439.51 47.31% 1199.83 1357.55 1111.89 81.90%

1998-99 (T&D)

10630.59 5359.41 49.59% 1240.62 1374.64 1108.36 80.63%

1999-2000 (Distribution)

9996.52 5603.24 43.95% 1230.30 1454.36 1097.85 75.49%

1999-2000 (Transmission)

11197.40 10645.70 4.93% 1165.60 1411.63 1113.79 78.90%

1999-2000 (T&D)

11197.40 6252.16 44.16% 1165.60 1585.75 1268.00 79.96%

2000-01 (Distribution)

10863.67 6080.42 44.03% 1412.53 1652.78 1276.27 77.22%

2000-01 (Transmission)

12400.03 11758.43 5.17% 1399.72 1607.63 1108.13 68.93%

2000-01 ( T&D)

12400.03 6974.76 43.75% 1399.72 1793.00 1459.66 81.41%

2001-02 (Distribution)

10992.42 5773.21 47.48% 1519.13 1751.56 1300.12 74.23%

2001-02 (Transmission)

12435.14 11866.63 4.57% 1204.11 1719.32 1126.47 65.52%

2001-02 (T&D)

12435.14 6645.21 46.56% 1204.11 1933.19 1461.22 75.59%

2002-03 (Distribution)

11363.18 6731.78 40.76% 1475.64 1968.58 1607.72 81.67%

2002-03 (Transmission)

11889.39 11410.54 4.03% 1624.60 1486.79 1225.30 82.41%

2002-03 (T&D)

11889.39 6779.14 42.98% 1624.60 1979.73 1617.73 81.70%

197

Table 25: Sources & Application of Funds Sources of Funds

Rupees in Million Equivalent US$ (Million)

Internal Resources 9,816 222 Grant ODA grant towards State govt. equity to GRIDCO

2,260 63

ODA grant transferred to GRIDCO as GoO grant

1,265 34

Loans World bank 14,419 350 State Government 960 26 ADB 2,025 57 Other Sources 10,605 246 Total of Loans 28,008 678 Grand Total 41,348 997

Application of Funds

Item Rupees (Million) US$ Million Capital investment 35,370 840 Interest during construction

2,060 49

Reform Expenses 2,754 74 Repair and maintenance expenditure from ODA grant

400 12

Increase in maintenance inventory

765 22

Total Investment 41,348 997 Source: World Bank Staff Appraisal Report

198

Table 26: EXPENDITURE INCURRED ON CONSULTANCY SERVICES

Sl. No.

Project Agency Amount In million PS

Rupees in Crore@ Rs. 65/PS

Funding Agency

A Pre-reform

Consultancy KPMG led consortium

41.000 GoO

1 Reform Credit Switz Fast Boston (CSFB)

16.194 105.261 DFID Grant

2 PMU Merz McLilan Seaboard International

7.605 49.433 DFID Grant

3 ISP Price Waterhouse Coopers

4.668 30.342 DFID Grant

4

RIAP Price Waterhouse Coopers

7.884 51.246 DFID Grant

5

Training Centre

Price Waterhouse Coopers

0.150 0.975 DFID Grant

6

BEINA Social Study

Price Waterhouse Coopers

0.018 0.117 DFID Grant

7 RIAP Extension

Price Waterhouse Coopers

0.600 3.900 DFID Grant

8 TRISP Package

Price Waterhouse Coopers

3.715 24.148 DFID Grant

B

TOTAL

40.834

265.421

DFID Grant

Total amount

spent on consultancy

306.421

199

Kanungo Committee’s Findings and Recommendations

Encouraged by the Government of India, assisted by the World Bank, and

supported with grants from the government of U.K. (DFID), Orissa took the

initiatives and became the first state to reform its electricity industry. The

Orissa Electricity Reforms Act, setting out the basic frame work of the

reform, enacted in 1995 came in to force from 1st. April 1996. The principal

objectives of the reforms had been discussed earlier but out of so many only

three (03) objectives were achieved namely:

(a) Restructuring of the Electricity Industry for rationalization of

generation, transmission, distribution and supply of electricity.

(b) To provide avenues for participation in the industry of private

entrepreneurs, attract private investment and reduce the need for

government funding of the electricity sector.

(c) To provide a transparent mechanism for development and regulation

of the industry, including tariff fixation and dispute settlement,

through an independent, statutory body; the Orissa Electricity

Regulatory Commission.

The other expectations were yet to be realised.

The OERC has done pioneering work in our country in the establishment of a

regulatory mechanism for the electricity industry. The reform Act, which has

given the commission a wide mandate, requires it to act effectively and

independently. The OERC’s working in the last few years, has not been free

from problems. To avoid these, the following recommendations have been

made.

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1. To ensure that commission is fully functional at all times, the

government must appoint commissioners promptly. Action for filling

up vacancies should start early so that recommendations of the

selection committee are available to government at least two weeks

before the vacancy occurs. In the event an appointment or selection is

stayed by court, prompt action should be taken to have it vacated by

moving a higher court or a larger bench. Further nobody should be

considered for appointment unless there’s a clear possibility of his/her

serving for five years. To attract persons of ability, integrity, and

standing, wide publicity should be given while inviting nominations

for commissioners.

2. Budgetary allocation for the commission should be adequate.

Ordinarily, the government should not apply any budgetary cuts as

long as the amount proposed by the commission is within the limit of

license fees received. Accounting regulation for the commission should

be settled forthwith and budgeted outlays placed in a banking account

at the disposal of the commission for incurring expenditure in

accordance with the accounting regulation, without further reference to

the government.

3. The commission should institute regular systems of monitoring to

ensure that the prescribed standards of performance are actually

adhered to in the industry.

4. The government and the commission should have purposeful

interaction on a wide range of issues of monitoring, problem solving,

planning and development of the state’s power sector. For exchange of

information and discussion on administrative matters of mutual

interest, the government should interact with commission’s secretary.

There should also be system of meeting with the commissioners, at

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least once a year, taken at an appropriately high level to discuss and

settle matters involving important issues of policy.

5. The reforms were conceptualized under the guidance of the World

Bank and the road map for implementation was set out in its SAR

(Staff Appraisal Report). The assumption in the SAR of growth in the

demand for power in the state was highly ambitious, in terms of totals

and compositions. The demand for industrial power (EHT Supply),

which subsidizes domestic demand (LT supply), was grossly under

realized while domestic and commercial demand with high losses grew

fast. T & D losses, which were excessively high and were targeted for

substantial reduction, could not be brought down. Billing and

collection efficiency under the privatized distribution companies were

(DISTCOs) far from improving, actually worsened and theft of

electricity continued unabated.

6. The reform scheme was further vitiated by sharp, upvaluation of assets

at the time of transfer to utilities. This led to a steep increase in the cost

of power. Unrealistic assumptions that GRIDCO would become profit-

earning from 1999/98 led to the abrupt withdrawal of subsidy by the

state government from 1996/97. There has been considerable increase

in the average tariff at a cumulative rate of 15.5% annually over the

last nine years without any perceptible improvement in customer

service. The cross subsidy has also been brought down, particularly in

the post reform period, thereby casting a heavier burden on domestic

consumers.

7. Unabated increase in tariffs without a perceptible increase in techno-

commercial losses or improvement in customer service has led to

growing public discontent against the reforms. This situation has

worsened because of spiralling increase in costs and deteriorating

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health of the utilities. The DISTCOs & GRIDCO have been rendered

utterly unviable as a result of their inability to reduce T&D losses,

control rampant misuse, and theft of electricity and contain costs.

DISTCOs are unable to pay salaries to their employees without

defaulting on payment to GRIDCO towards the purchase of power.

GRIDCO also is unable to recover costs and is incurring heavy debts to

finance losses year after year. In this situation, the generating

companies are also facing inadequate cash realisation. The situation

has become so critical that the private sector partner in one of the

DISTCOs, AES, has abandoned the management of CESCO, which is

now being managed by a CEO appointed by regulatory authority. It is

recommended that the CEO of CESCO should be for full time.

8. The key to the revival of the sector lies in improving the efficiency and

bringing down the costs. By efficiency improvement not only can

customer services be geared up but T&D losses, currently at an

unacceptably high level, can also be brought down substantially. The

reform scheme sought to address the problem of T&D losses through

(a) capital investment to strengthen the T&D system so as to reduce

technical losses, and (b) privatisation of distribution to bring in better

management skills and practices for enforcement of accountability to

reduce commercial loss. Neither of these two has succeeded so far.

9. Large capital investments have been made but not a single project has

been completed despite considerable time overruns. The delays in most

cases for want of forest clearance, land availability or right of way.

Since none of the projects has been commissioned, no benefit has been

realized from the investments worth more than 6000 million rupees out

of funds borrowed from the World Bank carrying heavy debt-servicing

liabilities. Efforts need to be intensified to complete and commission

the ongoing works. No new work should be contracted until the

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majority of the ongoing works is completed. With the commissioning

of these works, there should be a significant improvement in system

reliability and reduction of technical losses, which would benefit

impact on cost reduction.

10. As far as massive commercial losses are concerned, the results

achieved over the last five years are insignificant. The T&D losses,

which were 46.94% in the 1995/96 as shown by the audit, are now

46.63% as reported by the utilities themselves. The loss is more

staggering in the LT segment at 68%. The DISTCOs, in their

projections, have proposed very little reduction. The rate of loss

reduction that needs to be attempted and achieved in the next five years

must not be less than an average of five percent which, in our view, is

well within reach. Attainment of the goal would, however, call for

determined, comprehensive and relentless effort. The following are

some suggestion in this regard:

(A) A concerted drive to remove illegal connections (such as hooking)

and effective measures to convert them in to regular connections

followed up by systematic billing and collection of energy charges.

(B) Should the DISTCOs wish police force escort for carrying out

special drives to prevent unauthorized use of electricity, over and

above the comfort of the chief secretary’s circular to DMs and SPs

asking for prompt intervention in the event of violence by antisocial

elements, the government should make available to the companies

the requisite support on payment of costs.

(C) Hundred percent consumers metering within a year and immediate

metering at the low voltage terminals of the step-down transformers

should be provided so that supplies in to HT & LT systems can be

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quantified for purpose of proper energy accounting, which is

practically missing.

11. A major cause of sharp increase in the cost of power was steep

upvaluation of assets at the time of transfer to GRIDCO. It called for

substantially higher provision for the depreciation as well as return on

capital. Neither these could be met because of short fall in revenue. In

these circumstances it would be worth while in keeping the revaluation

in abeyance till the system is brought to balance. In fact there’s a case

setting aside the revaluation of OHPC, which is expected to be

profitable in the years to come. In addition to this, state government

may agree to allow a moratorium on debt servicing to the state except

the amounts in respect of loans from the World Bank, which the state

government would need to pay to the centre. After applying these

correctives and also taking credit for T&D loss reduction at an average

rate of five percent per year, the revenue gap at the existing retail tariff

would show a decline but would still be substantial. The unavoidable

revenue gaps would need to be financed from the sources other than

debt. Since the state governments are themselves passing through

severe financial stress, it may not be realistic to ask them to make a

sacrifice over and above what has been suggested already.

12. An exercise has been carried out to estimate the annual shortfall on a

cash flow basis without tariff hike but assuming that collection

efficiency of the DISTCOs would progressively improve from the

present level of 76% to reach 95% by the year 2005/06 instead of

ending up with a collection efficiency of 84% proposed by them. With

a tariff hike of 18% in 2005, the entire cash deficit would disappear

and the year 2005/06 would witness both an operational profit as well

as marginal cash surplus. The sector as a whole would turn around in

2005/06. The consumers could be called upon to pay higher tariffs at

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that stage because by then the utilities are expected to have shown

evidence of their concern for and efficiency in T & D loss reduction

and improvement of customer service; not otherwise.

13. To bring the reforms back on the rails, the World Bank and the DFID

who helped Orissa initially, and hopefully have retained their interest

in the reform, should come forward with a suitable package to fill the

revenue gap in the intervening years. Without this interim financing

(estimated at 32400 million rupees), there seems hardly any prospect of

the reform coming to fruition. The Government of India should not

only persuade them to do so but also extend a helping hand in sharing

the responsibility of interim financing of the revenue gap.

14. Once decision is taken on interim financing and its apportionment, the

DISTCOs and GRIDCO may be pinned down to specific performance

parameters by desegregating the proposed T&D loss reduction

DISTCO-wise.

15. In the prevailing run down state of GRIDCO and DISTCOs, no durable

rehabilitation is possible without interim financing of unavoidable

losses. However it needs to be emphasized that no amount of support

from outside would succeed unless the utilities conduct themselves

with greater sense of responsibility. Privatization was seen as a means

to improve the performance of DISTCOs. The private sector partners

need to bear in mind their crucial role, which cannot be performed

satisfactorily unless they face the task as a challenge and an

opportunity and take the industry forward in the true spirit of

partnership and for mutual benefit.

16. The private promoters of DISTCOs neither brought superior

management skills nor did they arrange financial support even by way

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of working capital for companies, which were in dire need of capital,

working capital in particular. Instead of using the good offices of

BSES to secure working capital in terms of clause 8.1 of the

shareholders agreement for the three DISTCOs under their

management, the DISTCOs have persistently defaulted in payment to

GRIDCO towards purchase of power. The outstanding overdue of

GRIDCO as on 30 September 2001 against these three DISTCOs is

6807.2 million rupees including bonds issued by them in lieu of cash

payments. So far as the other distribution company CESCO is

concerned, the situation is worse. AES, the private partner, never

fulfilled its commitment to bring working capital. They were allowed

to pile up unpaid power purchase bills amounting to 4030 million

rupees by the time they walked away in August 2001. Now that the

AES have abandoned CESCO, GRIDCO seems to be left with hardly

any other option except exploring a legal remedy. As far as BSES-

managed DISTCOs are concerned, the attitude of deliberate default in

payment to GRIDCO must end. The BSES should make all efforts to

bring in working capital in terms of the shareholders agreement.

17. The system of escrow put in place to secure regular payments to

GRIDCO towards power purchase has not worked. With the package

of financial relief recommended by us along with enforcement of the

provisions of the shareholders agreement, the escrow mechanism

should be made to work and strictly enforced. (Escrow-In the event of

non-payment by the SEB, IPP shall have recourse to L/C and revenues

shall be accumulated in the escrow account. In case funds in escrow

account are insufficient, IPP may invoke State Govt. guarantee)

18. There is an urgent need to develop trust and goodwill between the

employees and the management. The vital role of the employees and

their associations in building up the industry needs to be taken more

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seriously. While firm action against known miscreants is necessary to

enforce discipline and accountability this cannot be done without

skillful handling of situations and willingness to mitigate genuine

grievances. A specific matter in this connection relates to pensionary

benefits. Employees apparently have found that the pension scheme

preferred by them, and also adopted by the companies, has turned out

to be disadvantageous, particularly for those who came over from the

government in a higher age group. In a matter like this neither the

present employers nor the government should take any rigid stand. The

effort should be to find a solution, which may not even be difficult to

reach. Likewise, there is an apprehension the liabilities of

government/GRIDCO towards the Pension Trust may not have

assessed correctly. This is a matter of actuarial calculation, which may

affect the viability of the pension funds, so there should be no

reluctance to take a fresh look at the estimates.

19. Orissa is richly endowed with natural resources, and now has the

additional advantage of the surplus power. This combination needs to

be exploited to accelerate industrialization of the state through

vigorous marketing of power by offering more competitive rates. By

selling surplus power to industries, even at tariffs lower than prescribed

by the OERC, not only would the state benefit from industrialization,

but the DISTCOs themselves would also stand to gain as long as they

recovered costs at the margin. The tariffs fixed by the OERC should be

treated as the ceiling in each category, and utilities should have the

freedom to supply power at lower rates in exercise of their commercial

judgement.

20. With restructuring and privatization, there’s a much greater need now

for rigorous enforcement of safety norms in the electricity industry.

However, care needs to be taken to see that there’s no mindless

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expansion of the Electrical Inspectorate. Services of chartered

engineers, under a strict system of empanelment and penalty in the

event of misconduct, may be utilised for the purpose of supplementing

human resources of a slim, well structured inspectorate.

21. The services of local consultants as well as highly rated consulting

firms of international repute were used extensively in the preparation

of blueprint of reform, and to assist the utilities in developing internal

systems of operation management, financial control, technical services,

contract management, project implementation, etc. The cost incurred

so far is a staggering 3060 million rupees. However, judging by the

fate of reforms and the state of the utilities it is clear that the utilities,

for whose benefit the consultants were engaged, did not assimilate

much of their advice. Instead of developing an inner strength with the

assistance of consultants, they tended to be excessively dependent on

them leading to a near-atrophy of organisational strength. We suggest

that this practice, which weakens organisation rather than

strengthening them and demotivates employees instead of improving

their skill and confidence, should end as soon as possible.

22. Close attention should be given to strengthening the managerial

competence of GRIDCO, which is not only financially sick but also

organisationally very weak. The following recommendations are made

in this connection.

• The senior management of GRIDCO should be selected on the

basis of merit and must be appointed for a fixed term of three to

five years.

• The SLDC (State Load Dispatch Centre) and its commercial

counterpart, the energy billing centre, should be provided with the

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necessary staff whose skills should be substantially honed and

upgraded by regular training.

• GRIDCO’s PMU (Project Management Unit) should take over the

responsibility of all capital works irrespective of the source of

funding. It should also monitor capital works executed by the

distribution companies in addition to managing and monitoring.

23. The entire power sector needs top management of a high calibre just as

it requires an efficient work force motivated to further the interest of

the industry. The task before the management is daunting.

Appointments to the boards of directors of all the utilities need to be

reviewed to ensure that professionals including administrators with

competence, vision and commitment may enrich the utilities at the top.

The prevailing system of part time appointments to key positions in the

sector, including the chief executive officer of the OHPC should end.

The chief executive officers of the DISTCOs should be stationed at

their respective head quarters.

24. The committee did not get the evidence of any innovative practice

introduced in the management of the privatized DISTCOs. However, in

some of the DISTCO areas, an experiment is in progress to involve

village communities in streamlining power supply in rural areas. While

the results seem to be encouraging, the exercise currently being

conducted by consultants can succeed in the long run and over large

areas only if the programme is implemented by DISTCO official

themselves.

25. It is recognised that regulatory commission need to lay down norms for

tariff determination, which would enable the utilities to have a clear

idea of the range in which tariffs may move over a reasonable period.

A multi-year tariff regime is therefore, being advocated by experts.

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The OERC has also laid down norms in certain areas though much

more needs to be done. But no purposeful result can be achieved in the

matter of multi-year tariffs unless there is a reasonable financial

balance. Serious efforts are required to provide financial balance to the

sector before multi-year tariffs can become a reality.

26. Another idea often advocated by experts is multi-buyer model of

power trading. Here again attainment of financial balance is an

essential pre-requisite to provide a basis for competition through

various models of multi-buyers system as distinct from the single-

buyer model adopted by Orissa as well as other states who have

embarked on reform. In the prevailing situation of near bankruptcy of

GRIDCO and disarray in the functioning of DISTCOs, the sector

should be spared any further trauma. Meanwhile, GRIDCO needs to

strengthen itself to develop ability and skill to handle the power trading

function which calls for, among other things, prompt exercise of

commercial judgement. Urgent attention should be paid to develop this

within the organisation. It would be of advantage to develop within

GRIDCO a well functioning trading unit which may eventually be

turned in to an independent trading organisation as a step towards

bringing in a competitive regime that would provide the consumer the

opportunity to choose the source of this power supply.

27. Rural electrification seems to have unintentionally become the worst

casualty of the reform process. With the restructuring of OSEB, and

privatization of DISTCOs, the rural electrification wing of OSEB was

disbanded and it was left to the DISTCOs to carry on with whatever

schemes were in the pipeline. Since the activity is commercially not

attractive, the DISTCOs cannot be expected to be very enthusiastic

about rural electrification. The interest of DISTCOs has further

slackened because even the modest rural electrification work done by

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them has not been paid for in spite of the fact that an amount of Rs. 23

Crore of capital subsidy due was certified by OERC several months

ago. No fresh scheme of rural electrification seems to have been posed

for funding support of agencies like REC, nor any scheme drawn up

for the purpose. Another regrettable feature is the utter lack of concern

for productive use of electricity for rural development through

agriculture pumping. In terms of agricultural demand for power among

states, Orissa is practically at the bottom. What is worse is that

agricultural demand for power in the state has gone down from a

meagre 6% in 1992-93 to a dismal 3% in 1999-00, compared with

national average of 30%. No single department of the state government

is entrusted with the administrative responsibility to plan, promote and

monitor growth and press for rural electrification for development of

irrigation pumping which is vital rural development. Under a high

priority national plan, all villages are required to be electrified by

March 2007. For a state like Orissa, with a 40% of the population from

weaker sections of scheduled castes and scheduled tribes living in

remote areas, the leeway to be made is large. Kutir Jyoti program

needs to be pursued with vigour. It must however be ensured that the

benefits of subsidised electricity supply under this program flow to the

targeted beneficiaries the goal is unlikely to be reached unless

determined efforts are made and an effective machinery is put in place

for planning, execution and monitoring of rural electrification projects.

The vacuum caused by abolition of the rural electrification wing of the

OSEB needs to be filled up and an alternative system created. The

following recommendations are made in this connection:

a) A Rural Engineering Planning Organisation (REPO)

should be set up under the Government to provide

focus and direction to this vital programme, to prepare

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specific schemes, pose them to funding agencies and

over-see utilization of the funds procured.

b) REPO should have under it four Rural Electrification

Planning Units (REPU), each corresponding to a

DISTCO with which it would need to work in close

coordination. These units would draw up, detailed

schemes of rural electrification.

c) Prioritisation of villages for electrification should be

done by REPUs in consultation with the collector of the

concerned district.

d) Execution of the works would be the responsibility of

the concerned DISTCOs.

e) REPUs would need to monitor the execution and report

completion of schemes and the expenditures incurred

thereon to the Collector of the district and the State

REPO.

f) On the basis of the Collectors’ certificates of

satisfactory completion, the state Government should

promptly settle subsidy payments admissible to

DISTCOs.

g) Government would need to provide DISTCOs with

capital subsidy; revenue requirements would, in normal

course, be considered by OERC as a part of tariff

exercise.

28. Our recommendation would help rehabilitate the utilities, bring

stability and promote growth of the power sector only if these are

implemented as a package and implementation is managed and

monitored closely. The reform adopted by Orissa may have been

flawed, but mid-course corrections could have been managed rather

than its success taken for granted. The committee’s recommendations

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towards putting back the reform on rails would succeed only if the

need for reform management is recognised and a system is put in place

by the government for regular monitoring, co-ordination and mid-

course correction. It is interesting to know that of all the major

parameters of reform laid down in the SAR; one of the few that proved

realistic was tariff. Retail tariff has been fairly close to the SAR

assumption in the first two years and substantially higher since 1998-

99. Thus, consumers have not failed to provide support; they have

made ample sacrifice in search of better quality of service which has

eluded them so far.

29. Power sector would succeed if the utilities bring in efficiency, cut

costs, reduce losses and ensure greater consumer satisfaction. It would

also require strong enforcement to ensure that consumers of electricity

pay for its use. All sections of the society, particularly those, who are

in a position to influence public opinion, have the responsibility to

provide the requisite support. Revival of the power sector would

depend to a large extent on how fast a consensus is built in this vital

area.

30. The state’s power sector is now on the brink of the crisis. It is high

time all agencies namely, the state government, the central

government, the world bank and the DFID, got together and took a

holistic view on what can be done by each to rescue the reform. If the

electricity reform fails in Orissa, it would have its inevitable adverse

impact on reform all over the country. What have taken place in the

electricity industry of Orissa is only restructuring, privatization and

establishment of a Regulatory Mechanism. The real reform, which

brings in its wake benefits to consumers, strength to the industry and

growth for the economy has yet to come.

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Turnaround of GRIDCO / OPTCL - A Case Study

All the major steps in the restructuring process have since been taken as

envisaged under the reform scheme:

• OSEB was restructured and corporatised in to Grid Corporation of

Orissa (GRIDCO) and Orissa Hydro Power Corporation (OHPC) in

April 1996.

• The Orissa Electricity Regulatory Commission (OERC) was

established in August 1996.

• Orissa Power Generation Corporation (OPGC) was privatized with

divestment of 49% stake and transfer of management control to a

private operator, AES in January 1999.

• Four distribution companies (DISTCOs), incorporated as wholly

owned subsidiaries of GRIDCO, were privatized with transfer of 51%

stake to private operators: three of these, namely, NESCO, WESCO

and SOUTHCO were acquired by BSES in April 1999 and the fourth,

viz. CESCO by AES in September 1999.

GRIDCO disinvested 51% of its equity holding to private investors with

strong financial standing & technical capabilities. 10% of the equity has been

reserved for the employees of GRIDCO- that would entitle them to direct

monetary and welfare benefits. GRIDCO retains 39% of the holdings in the

DISTCOs.

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Transfer of Assets

The restructuring was done in two steps through the instrumentality of

transfer scheme framed under the Orissa Electricity Reform Act, 1995. Under

the first transfer scheme (effective from April 1, 1996) the assets, liabilities,

proceedings and personnel of erstwhile OSEB were transferred to OHPC (for

hydel generation) and GRIDCO (Transmission and Distribution). The second

transfer scheme (effective from November, 1998) further transferred the

distribution related assets, liabilities, proceedings and personnel of GRIDCO

to four wholly owned companies of GRIDCO.

RESTRUCTURING EXERCISE INVOLVED CERTAIN MEASURES,

WHICH CAST A HEAVY STRAIN ON THE FINANCES OF GRIDCO

Under the Transfer Scheme of April’96, the state government took over the

Transmission and Distribution assets of OSEB (book value plus capitalized

expenses and interest at 1200 Cr.) and reinvested them in GRIDCO after

upvaluing by an additional Rs. 1194 cr. (additional 134%). Against this

upvalued amount of 1194 Cr, the state Govt. adjusted subsidies and electricity

charges payable to OSEB/GRIDCO totalling Rs.340 Cr. In addition GRIDCO

issued Rs. 253 Cr. Worth of shares and Rs. 400 Cr. Worth zero-coupon bonds

to the state govt. This left GRIDCO with a serious cash shortage right from

day one and compelled it to default it to generating companies and other

suppliers. In addition Rs. 1146 Cr. of loan and liabilities were also assigned to

GRIDCO.

The upvaluation exercise was prompted by considerations including the need

to have a capital base capable of absorbing substantial debt funds needed for

the up gradation of the T&D system and the requirement of having a self

financing ratio of 20% and an adequate debt-equity ratio as per World Bank

conditions. It was also felt that the assets should be valued on the basis of

216

their business potential and replacement value, not their book value. The

revaluation exercise also enabled the cash strapped state govt. to “Adjust”

dues totalling Rs. 340 Cr. Payable to OSEB/GRIDCO against the

upvalued amount.

Table 27: Revaluation of Assets

Details of Revaluation done in Transfer Scheme dated April 1,

1996

Rs. in Crores

Book Value of T&D Asset 1103.2 Interest and expense capitalised 97.5 Total 1201.0Uplift in Value of Assets 1120.0Total 2320.7Depreciation 363.0Net Fixed Assets of GRIDCO as on April 1, 1996

1957.7

Total Revaluation Uplift In Assets 1120.0 Further Adjustment 74.0 Total 1194.0Adjustment Subsidy due to OSEB 301.2Electricity charges receivable from Government

39.2

Reduction in O&M stock 50.6Total (A) 391.0Fresh Equity to State Govt. 253.0Zero Coupon Bond to State Govt. 400.0Bonds issued to Pension Fund 150.0Total (B) 803.0Total (A+B) 1194.0 Source-Price Water House Coopers

217

The impact of revaluation on the distribution companies has been lower than

that to GRIDCO as they were allocated only project specific liabilities

totalling Rs. 630 Cr. for all four distribution companies put together, while

GRIDCO retained in their books liabilities (including accumulated losses)

totalling about Rs. 1950 Cr. While the assets were upvalued, there was no

such upvaluation of the liabilities. Besides, as stated earlier, the distribution

companies were assigned only project related liabilities. The only component

of asset upvaluation which has a bearing on tariff depreciation, which stood at

Rs. 81.69 Cr. in FY96 on the eve of the upvaluation and was pegged at Rs.

128.02 Cr. for FY98 by OERC in their tariff order effective from April 1,

1997.

The difference of Rs. 46.33 Cr. (Rs. 128.02 Cr. – Rs. 81.69 Cr.) in the

depreciation (which also included depreciation of assets created during FY97)

formed only 3.2% of GRIDCO’s total revenue requirements of Rs. 1451 Cr.

allowed by OERC. Hence the impact of upvaluation on distribution tariff has

been estimated to be only about 2.5%. Further, it must be emphasized that it is

not the upvaluation exercise per-se that resulted in GRIDCO’s cash crunch;

the cause is rather the “adjustment” of the totality of its receivables from the

state government (about Rs. 340 Cr.) right from inception.

Privatization of Distribution Functions:

In pursuant to the Orissa Electricity Reform (Transfer of Assets, liabilities,

proceedings & personnel of GRIDCO to distribution companies) Rules, 1998,

the government of Orissa transferred the distribution assets and properties

along with personnel of GRIDCO to 4 distribution companies namely

CESCO, NESCO, WESCO, and SOUTHCO continued to function as

affiliates of GRIDCO up to 31.03.1999 and thereafter functioned under the

distribution & retail supply license obtained from OERC.

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Objectives of Privatization of Distribution Function:

A. Operational Improvements:

(i) Improve quality of service to consumers

(ii) Improve operational efficiencies & reduce losses.

B. Financial Benefits:

(iii) Attract private investment in to the distribution business

(iv) Reduce the need for government funding of the electricity

sector

(v) Contribute to increased economic growth in Orissa.

C. Employee Considerations:

(vi) Create opportunities for secure & increasingly rewarding

employment for the qualified personnel

(vii) Provide a stable environment for employees

D. Sale of all 4 Zones to promote competition

In keeping with the objectives of power sector reform and the commitments

given to the World Bank by the state government, the distribution function

was required to be privatized. After considerations of various options

available for privatization, the corporation decided to adopt the best mode of

Joint sector/ Joint venture route. The sequence agreed was that the four

distribution zones which were functioning under the corporation will be

converted in to four distribution companies as its wholly owned subsidiary.

In spite of these pragmatic reform programmes, GRIDCO’s financials

worsened in the year 2000 and debt level of the company rose to the all time

high. Then state government did intervene and constituted a high power

committee lead by Mr. Sobhan Kanungo (I.A.S), to examine the fault lines

and asked the committee to suggest the measures to put the GRIDCO back on

track. After adhering to committee norms, improvements in all sectors are

219

visible now with increase in earnings and total turn around, with the GRIDCO

posted a net profit in FY 2004-05. The highlights of the results as follows:

1. GRIDCO started trading of its surplus power with the utilities/SEBs

through the Power Trading Corporation of India Ltd. (PTC) by

entering into an Agreement signed on 03.07.2003. The trading was

started with effect from 05.07.2003 initially for an average of 100 MW

@ Rs.2.60/unit for the evening peak @ Rs.2.00/unit for the off-peak

(18 hours) a day. The average rate was Rs.2.15/ unit Further, GRIDCO

has also entered into an agreement with NTPC Vidyut Vyapar Nigam

Ltd. (NVVNL), a wholly owned subsidiary of NTPC on 24.09.2003 for

an average of 100 MW trading. Trading of power with NVVNL was

started with effect from 01.10.2003.

During November, 2004 the peak export is 557 MW, off-peak export is

427 MW and the average export is 460MW.

Peak Trading 550 MW Off peak Trading 430 MW Average Trading 460 MW

2. T & D losses, which were excessively high and were targeted for

substantial reduction, could be brought down gradually. Billing and

collection efficiency under the privatized distribution companies

(DISTCOs) started improving, theft cases of electricity started falling

and due to the introduction of one time settlement of theft and irregular

connection cases, many new customers were created over the years and

receivable collection started increasing.

Steps taken in this regard to reduce T&D losses are through (a) capital

investment to strengthen the T&D system so as to reduce technical

220

losses, and (b) privatisation of distribution to bring in better

management skills and practices for enforcement of accountability to

reduce commercial loss (D) Hundred percent consumers metering

within a year and immediate metering at the low voltage terminals of

the step-down transformers were provided so that supplies in to HT &

LT systems can be quantified for purpose of proper energy accounting.

Year

1999-2000

2000-01 2001-02 2002-03

2003-04 2004-05

% of T&D Loss

44.16% 43.75% 46.56% 42.98% 40.14% 38.93%

Collection as % of Billing

79.96% 81.41% 75.59% 81.70% 83.25% 88.68%

3. An exercise was carried out to estimate the annual shortfall on a cash

flow basis without tariff hike but assuming that collection efficiency of

the DISTCOs would progressively improve from the present level of

76%(2001-02) to reach 95% by the year 2005/06 instead of ending up

with a collection efficiency of 84% proposed by them. Already 2004-

05 witnessed a collection efficiency of 90%.

With a tariff hike of 18% in 2005, the entire cash deficit would

disappear and the year 2005/06 would witness both an operational

profit as well as marginal cash surplus. The sector as a whole would

turn around in 2005/06, which includes the distribution companies

also.

The consumers could be called upon to pay higher tariffs at that stage

because by then the utilities are expected to have shown evidence of

their concern for and efficiency in T & D loss reduction and

improvement of customer service; not otherwise.

221

4. To bring the reforms back on the rails, the World Bank and the DFID

who helped Orissa initially came forward with a suitable package to

fill the revenue gap in the intervening years. Without this interim

financing (estimated at 32400 million rupees), this gradual turnaround

in GRIDCO’s fiscals were unlikely and hardly there was any prospect

of the reform coming to fruition.

5. The system of escrow put in place to secure regular payments to

GRIDCO towards power purchase has not worked initially. With the

package of financial relief recommended along with enforcement of

the provisions of the shareholders agreement, the escrow mechanism

has started working and has been strictly enforced.

6. The services of local consultants as well as highly rated consulting

firms of international repute were used extensively in the preparation

of blueprint of reform, and to assist the utilities in developing internal

systems of operation management, financial control, technical services,

contract management, project implementation, etc. The cost incurred

so far is a staggering 3060 million rupees. Judging by the fate of

reforms and the state of the utilities it is clear that the utilities, for

whose benefit the consultants were engaged, did not assimilate much

of their advice or it did not reach to the bottom line managers. These

services of the consultants, which weakened the organisation rather

strengthening them, were stopped and government appointed efficient

bureaucrat in-charge of GRIDCO, which made turnaround a reality and

it has been decided to keep the tenure of CMD, GRIDCO fixed for 03

years, prior to which they should not be disturbed on normal course.

Chief executive officers of the DISTCOs are now stationed at their

respective head quarters.

222

7. To ensure that commission (OERC) is fully functional at all times, the

government started appointing commissioners promptly because

OERC has done pioneering work in our country in the establishment of

a regulatory mechanism for the electricity industry. Commission

started instituting regular systems of monitoring to ensure that the

prescribed standards of performance are actually adhered to in the

industry.

8. The government and the commission started interacting on a wide

range of issues of monitoring, problem solving, planning and

development of the state’s power sector. For exchange of information

and discussion on administrative matters of mutual interest, the

government evolved a mechanism to interact with commission’s

secretary.

223

Comparison of Financial Performance – Orissa Vis-à-vis Andhra Pradesh Table 28: Financial Result Analysis of Andhra Pradesh

Particulars

2003 – 04

2004 - 05

1. Total Income

2468.37

2416.40

2. Total Expenditure

2481.77

2422.47

3. Profit / (Loss) before Tax

13.40

6.07

4. Provision for Income Tax

----------

0.45

5. Profit / (Loss) after Tax

(13.40)

(6.52)

6. Net prior period credits / (Charges)

19.38

9.13

7. SURPLUS / (DEFICIT)

5.98

2.61

• % increase in Profit : 129.01% • % increase in Income : 2.15% • % increase in Revenue : 5.84% • % increase in Sales : 11.98% • % reduction in Distribution Loss : 1.21% • % reduction in distribution Transformer Failure: 0.82%

224

Table 29: Financial Result Analysis of Orissa

Particulars

2002 – 03

2003 - 04

1. Total Income

1686.33

2809.74

2. Total Expenditure

1865.43

1921.62

3. Profit / (Loss) before Tax

(179.70)

888.12

4. Provision for Income Tax

------------------

------------------

5. Profit / (Loss) after Taxation, contingency & Resv.

(59.80)

41.11

• % increase in Profit : 231.18% • % increase in Income : 66.61% • % increase in Sales : 31.11% • % reduction in Distribution Loss : 3.24% • % reduction in distribution Transformer Failure: 1.17%

225

SOCIO ECONOMIC IMPACT ASSESSMENT OF POWER SECTOR

REFORMS: A MICRO LEVEL ANALYSIS

V.1 Introduction

5.1 Aggregative analysis as presented in the previous chapters gives a

macro perspective of the different aspects of power sector reform in Orissa

and its impact. However, the analysis of aggregated data may not serve to

bring out the subtle nuances of reform and its impact at the user level, the

spatial variations and ground-level perceptions. Accordingly, the present

chapter proposes to develop a general micro level perspective about the effect

of reform on different user categories on the basis of various impact

parameters. The data collected from the users is both factual and perception-

based.

5.2 These disaggregated data are collected from different sources and from

different districts of the state of Orissa. The sources are:

a) households,

b) commercial and small industrial establishments,

c) principal informants including key power sector

functionaries, high-level officials of the Government of

Orissa and user group representatives and

d) the Focus Group Discussions (FGDs) in the selected sites.

The instruments1 of data collection consist of a structured questionnaire for

households, FGD dairies, an open ended checklist for commercial and small

industrial users, a list of issues in connection with the power sector for being

discussed with the principal informants and also informal discussions. After

pilot testing of the instruments and rigorous training of the investigators for

administering them, the actual field investigation was conducted over a period

of 4-5 weeks in the months of November – December in 2003. The senior

226

members of the study team conducted some of the FGDs and principal

informant interviews themselves in two installments.

V.2 Micro Level Data Sources: Sampling Framework

5.3 The study on Socio-economic Impact of Power Sector Reform was

conducted in eight selected districts of Orissa, with 2 districts sampled from

each of the 4 geographical zones (North, South, East and West) of the State.

Figure-5.1 gives the design of the sampling frame. A total of 2112

households from 32 selected villages (falling in 16 sample blocks) and 8

selected urban centres were surveyed to elicit users’ perceptions on different

aspects of power sector reform.

227

Nandapur (LE)Bajapur (HE)

Chhutaraipur (LE)Nairi (HE)

Bhubaneshwar (Town / City)

Sanagarh (LE)Gopalpur (HE)

Patanda (LE)Kishor Prasad (HE)

Nayagarh (Town / City)

Mahul Chappal (LE)P Pathhar (HE)

Balaranga (LE)Bargoan (HE)

Sambalpur (Town / City) Sambalpur

Salgadia (LE)Santuri (HE)

Lunahandi (LE)Kundanali (HE)

Angul (Town / City)

Rajpur (LE)Padmanavapur (HE)

Lunghuri (LE)Damodarpur (HE)

Berhampur (Town / City)

Badagatiguda (LE)Chatikana (HE)

Dangasorda (LE)Chandrapure (HE)

Rayagada (Town / City)

Somapur (LE)Baligan (HE)

Malitira (LE)Purusandha (HE)

Bhadark (Town / City)

Machhala (LE)Deogaon (HE)

Khandara (LE)Lalahari Basti (HE)

Keonjhar (Town / City)

Note : LD = Less Developed Block & LE = Less Electrified Village : HD = Highly Developed Block & HE = Highly Electrified Village

Design of the Sampling Frame for Collection of Primary Data

O R I S S A S T A T E

Bhubaneshwar

Keonjhar

Bhadark

Rayagada

Berhampur

Angul

Gania

Bamra

Nayagarh (LD)

Nayagarh

East

ern

Zone

Wes

tern

Zon

e

(HD)

(HD)

(HD)

(LD)

(LD)

(HD)

Digapahandi

Sout

hern

Zon

e

(LD)

(LD)

Bissam Cuttack

(LD)

(HD)

(LD)

(HD)

Khurda (HD)

Ganjam (HD)

AthamallickAngul (LD)

Banarpal

Sambalpur (HD) Maneshwar

Khurda

Chilika

Ranapur

Nor

ther

n Zo

ne

Ghasipura

Joda

Ganjam

Keonjhar (LD)

Rayagada (LD)

Bhadark (HD)

Chandrapur

(HD)

(LD)

Chandabali

Banta

(HD)

(LD)

228

V.3 Analysis of Household Data

5.4 This section analyzes the information gathered from responding

households* using electricity on different aspects of power sector reform that

are closely linked to the stated objectives of:

increasing access to electricity,

improving the quality of power supply,

enhancing billing and collection efficiency in the distribution of

power, and

generating a system for better supplier-consumer interface that

includes quality customer care.

We have discussed the household level data in respect of all the

indicators for the pre reform and reform periods and for rural/urban areas. The

study conducted by Xavier Institute of management (1996) is supposed to be

used as the benchmark (baseline) in order to have a comparative perspective

of pre and post reform periods. But for all the indicators used in the present

study, we are not able to use Xavier institute’s study due to the following

reasons: (i) the sample size for the domestic consumers of the Xavier study

was 288 while in the present study it is 2112; (ii) the analysis of rural and

urban area separately as well as by social groups was not made in respect of

all the indicators in the Xavier study. Therefore, wherever possible, we have

used the Xavier’s study as benchmark, otherwise, we have used CMDR’s

field survey data for the pre reform period.

Profile of Sample Households

5.5 Of the 2112 sample households, rural households constitute 52 %

(1107) and the rest are situated in urban areas. A little more than half (52 %)

of the total sample households belong to the socially less privileged categories

(Scheduled Castes, Scheduled Tribes, Other Backward Castes), hereinafter to

be referred to as the ‘Less privileged class’. While more than 70 % of the

* On an average, the extent of non-response on different aspects ranges between 2 and 20 % of the total sample size.

229

rural households belong to less privileged castes, about 67 % of the urban

households belong to the privileged category. The sex ratio (number of

females per 1000 males) in rural areas is 826 while the same is 859 in urban

areas. The sex ratio among upper caste is in favour of females in both rural

and urban areas. Expectedly, the urban literacy rate comes out much higher

than the rural literacy rate, particularly for education at the secondary level

and beyond2. Thus, while for the rural sample the literacy rate at secondary

level and beyond is estimated to be about 47% of the total number of persons

in the sample, the same is close to 60% for all persons in the urban sample.

Across the different caste groups it is found that the less privileged categories

are always behind the privileged category as one move towards higher and

higher levels of education. Irrespective of the social category, female literacy

rate at all levels of education is always behind the corresponding male literacy

rate.

Access to Electricity

5.6 “Kutir Jyoti” Scheme: The government of Orissa has a special scheme

named ‘Kutir Jyoti’ that is intended to improve the access to and use of

electricity among the rural SC, ST and OBC households living below poverty

line (BPL). The survey data relating to the sample households shows a

significant number of forward caste households (about 14%) coming under

this scheme (Chart-5.1). This gives an impression that, like any other scheme

for the rural poor, the benefits of this scheme are also enjoyed by the

privileged category. About 29 % SC and 39 % ST households are covered

under ‘Kutir Jyoti’ scheme. The relatively low targeting of the scheme among

the sample households may also be due to the high illiteracy rate of the SC

and ST population and their ignorance of the schemes meant for their welfare.

2 The focus on secondary level of education and beyond it is based on the assumption that awareness about power sector reform is likely to be more crystallized at this level.

230

Chart 5.1: Composition of Kutir Jyoti Households

SC29%

ST38%

OBC19%

Forward Caste14%

5.7 Access to Electricity by Sample Households: From Table-5.1 it is

found that 85 % of the total sample households got their connection before the

reform in the power sector. There is no difference between the average

connected load of the households between pre reform and reform period. The

average distance from the nearest electric pole to domestic connection was 20

meters (distance) in the pre reform period while the same comes out as 28

meters during the reform period. The amount spent in getting connection is

found to be nearly double in the reform period than that during pre reform

period. As per the rules, the domestic consumers are expected to get

connection within 30 days of their application. During the pre reform period

(XIMB,1996) only 29 % of the total domestic consumers got connection

within 30 days while during the reform period (CMDR study) it is reported

that the average number of days to get connection is 21 days which seems to

be an achievement of the reform process.

231

Table 5.1: Indicators of Access to Electricity by Sample Households

Information on

Pre-reform period

Reform period

Percentage of sample households that received connection 85.0 15.0

Connected Load (in kwh) 1.4 1.4 Distance from the pole (in meters) 19.9 27.6 Amount spent in connection (in Rs) 854.7 1521.9 Time taken for getting connection in days (CMDR study) - 21

XAVIER study: % of HH got connection in <30 days 29 -

Metering of Electricity Use

5.8 Metered Connections: The reform aims at achieving 100 percent

metering of the use of electricity. In the sample taken up for study, about 17

% of rural households and 2 % of urban households revealed that they did not

have meters in the pre reform period (Table 5.2). During the reform period

about 10 percent of the households did not have meters (CMDR study, 2003)

while 19 percent households did not have meters during the pre reform period

(Xavier study, 1996). On the whole, the reform objective of 100% meter

connections to the households is yet to be achieved.

5.9 Functioning of meters: About 25 % meters were not in working

condition in the pre reform period, while the same declines to 3 % for the

reform period (Table 5.2). It thus seems that significant achievement in

respect of repairing and replacing the non-working meters has been

observed. This possibly reflects a greater emphasis of the DISCOMs not only

installation of meters but making them effectively functional.

232

5.10 Frequency of Meter Reading: The irregularity in meter reading has

declined from 26 % (Xavier study) in the pre reform period to about 8 %

(CMDR study) in the reform period. There is a significant improvement in

the frequency of meter reading (every 2 months) in rural areas during the

reform period (as reported by 74% of sample households in reform period

compared to 48 % in the pre reform period). Similarly, for the urban areas the

monthly reading of meter is reported to be more frequent during the reform

period by 66% of urban households, compared to 44 % in the pre reform

period (Table 5.2).

5.11 Complaints about Meters: More than 80 % of the rural households and

more than 90 % in urban areas did not lodge any complaint in case of non

working of the meters in the pre reform period. In comparison, during the

reform period this increased to 98 % and 96 %, respectively, of households in

rural and urban areas. It is significant to note that the proportion of

households going for lodging any complaint in case of defective meters

declined sharply (from 18 percent to 2 percent) during the reform period,

particularly in rural areas (Table 5.2). It is possible that there is less cause

for complaint as far as the working of meters is concerned in the reform

period and this is definitely an indicator of improving system efficiency in

energy accounting by the DISCOMs. There is an alternative viewpoint on

this aspect of metering and it is based on the widely reported dissatisfaction

about the customer care services of the DISCOMs. Thus, if the public

perception is that complaints lodged by them are less likely to receive

timely and satisfactory attention, there would be a clear disinclination to

access the existing grievance redressal system. However, the latter

viewpoint seems unlikely considering that the next two indicators relating to

customer care (for meter related problems) give a positive impression of

the reform impact.

233

5.12 Time taken for Repairing of Meters: As per the norm, in case of non-

working of meters, the concerned DISTCOM is required to attend to it within a

maximum period of 22 days from the day of complaint lodged by the consumer

household. For the sample households it is found that the number of days taken in

correcting/repairing the meter has been reduced on an average from 29 days in the

pre reform period to 17 days in the reform period in rural areas while the

corresponding decline in urban areas has been from 25 to 15 days. It seems that

reform has been successful in this respect, irrespective of whether the consumer

is from rural or urban area (Table 5.2). This again is an indicator of greater

responsiveness of the DISCOMs in attending to consumer complaints as far as

the grievance relates to the functioning of meters. 5.13 Payment for Repairing

the Meters: As per rules, if the officially supplied meter goes out of order due

to some inherent defect, it will be replaced/repaired without any charge from

the consumers. But if the consumer damages the same, a penalty has to be paid

by the consumer. It is observed that in the pre reform period the payment

made by the consumers, on an average, towards repairing/replacing the meter

was higher when compared to the amount of payment made during reform

period (Table 5.2). This is possibly an indirect corroboration of the idea that

perhaps during the pre reform period more meters were damaged by the

households (either by tampering or any other way) for which they had to pay

very high price towards repairing/replacing the meters. During the reform

period the payment made by the households has significantly reduced. It is

likely that the vigilance system instituted by the DISCOMs in the reform period has

been largely effective in reducing the incidence of tampering/damage of the meters

by domestic consumers in both rural and urban areas.

234

Table 5.2: Metering of Households in Rural and Urban areas

Figures in % of Responding Households

Rural Urban Total Indicators related to metering Pre-Reform Reform Pre-Reform Reform Pre-Reform Reform

1. Meter Connection CMDR Study (2003) Metered 83 84.2 97.6 97.9 Un metered 17 15.8 2.4 2.1 9.5 Total 100 100 100 100 Xavier Study (un metered households - 1996) NA 19 2. Working of Meters CMDR Study Working 87.2 95.3 96.1 97.7 Not Working 12.8 4.7 3.9 2.3 3.2 Total 100 100 100 100 Xavier Study (meters not working) NA NA 25 3. Frequency in Meter Reading CMDR Study (2003) Irregular 18.6 13.5 6.6 4.5 7.7 Monthly 30.3 9.5 44.3 66.2 Every 2 months 47.9 74.3 48.9 29.3 More than 2 months 3.2 2.7 0.2 - Total 100 100 100 100 Xavier Study (Irregular Meter Reading)- 1996 NA NA 26 4. Complaint lodged by consumers in case of meter not working CMDR Study (2003) Lodged 17.7 2.4 5.1 4.3 Not lodged 82.3 97.6 94.9 95.6 Total 100 100 100 100 Xavier Study (1996) Not available 5. Time taken for repairing the meter (in days) 29 17 25 15 6. Payment made by the consumers to repair the meter (in Rs.) 63.77 9.15 85.68 18.64

235

Uses of Electricity

5.14 Type of Use: The domestic consumers use electricity largely for the

purposes of lighting, cooking, washing, entertainment, refrigeration,

education, health and hygiene, etc. For the sample households it is observed

that during the reform period there has been a definite shift in the pattern of

use of electricity in case of both rural and urban area consumer households.

While the traditional use of electrical appliances for lighting and cooking

purposes appears to have declined (possibly due to greater economy of use

and better availability of alternative sources of energy, such as LPG), there is

relatively greater reporting of the application of electricity for non-

conventional purposes like domestic chores, education, entertainment,

health and hygiene among both rural and urban area consumers, and

more so in the case of the latter (Table5.3).

Table 5.3: Uses of Electricity by Households in Rural and Urban Areas Figures in % of total sample householdsRural Urban

Type of Use Pre Reform

Period Reform Period

Pre Reform Period

Reform Period

Lighting 39.97 32.54 28.99 17.36 Cooking 13.09 6.1 10.88 5.76 Washing Cloth 0.46 0.56 3.37 6.76 Entertainment 16.32 20.04 16.67 15.61 *Other domestic chores 28.35 35.21 30.8 39.34 **Any other use 1.81 5.55 9.29 15.17 Total 100 100 100 100 * Electrical Appliances, e.g: Grinder, Iron, Fan, Refrigerator etc. **Education, Health & Hygiene, Income Generating activities

5.15 Economy in Use: It is assumed that reform would induce economy in

the use of electricity through the rationalization of electricity tariffs. From the

field survey data it is found that more than 90 % (not shown in the table) of

the sample households (rural and urban) have reported practicing economy in

the use of electricity at their home in both pre reform and reform periods. It is

found that the women members of the household are in general more

conscious about the economy in use of electricity. Compared to about 60 %

236

women in the rural areas and 70 % women in the urban areas that are found in

the pre reform period to be more conscious about economy measures in the

use of electricity, these percentages has increased significantly in the reform

period as more than 70 % women in rural and 80 - 90 % women in urban

areas are found to be practicing economy measures (Table 5.4). This

gender aspect about the consumers’ response to the power sector reform

needs to be noted as this brings out the crucial role that women can play in

matters of socio economic importance to the family and the economy as a

whole.

Table 5.4: Economy in use of electricity by members of the household Figures in % of total sample households

Rural Urban

Members of the Household

Pre Reform Period Reform Period

Pre Reform Period Reform Period

Women 62.72 70.55 73.31 89.78 Men 27.65 22.78 20.75 7.3 Old People 1.75 1.67 1.82 0.73 Children 3.61 0.56 1.09 0.73 Every one 4.27 4.44 3.03 1.46 Total 100 100 100 100

5.16 Reasons for economy in use: The information gathered from the

households reveals that when asked to prioritize the reasons for practicing

economy measures in the use of electricity, 70 to more than 80 % of the

sample households give minimization of the electricity bill as the most

important factor. This evidence of a price impact is in accordance with the

expectation from reform. Energy saving gets the second priority among the

reasons stated by the households (Table 5.5). Chart 5.2 and 5.3 provide a

clearer picture of the reasons for the economy in use of electricity.

237

Table 5.5: Reasons for Economy in Use by Households in reform period and

Figures in % of responding households

Reasons Rural Urban To minimize the bill 76.7 86.9 Installation of china meters 1.7 0.7 Energy saving 21.7 12.4

Reasons for Economy in use of Electricity Chart 5.2 Chart 5.2 A

Rural

77

2

22

To minimize the bill Installation of China metersEnergy saving

Urban

87

1 12

To minimize the bill Installation of China meters Energy saving

238

Electricity Tariff

5.17 Change in Cost/Tariff of Electricity: The overwhelming majority of

household consumers in rural as well as urban areas perceives that price of

power has increased in the reform period. This is to be expected considering

the frequent hikes in tariff carried out in the reform period. What is

interesting, however, is that about 11 % rural and 4 % urban households

perceive a decrease in the price of power in the reform period (Table-5.6). It

is likely that these households are referring to the real price of electricity,

which after adjusting for the inflation rate during the period, is likely to

have come out as lower for the reform period in the perceptions of some

of the consumers. This is a possibility that also came out strongly in some of

the discussions with key informants from different user groups as well as

from the OERC functionaries.

Table 5.6: Perceived changes in electricity tariff in reform period

Perceived Change in Electricity Tariff Rural Urban

Increased 88.5 95.9

Decreased 11.5 4.1

Total 100.0 100.0

Figures in % of responding households

5.18 Collusion: An attempt has been made on the basis of the reported

information to relate the extent of use of electricity by a household

with the amount of payment for the same. It is assumed that the

number of power points in the households is a more accurate indicator

of actual/potential consumption of electricity than the units billed,

since there is a chance that tampering of meters by the consuming

household contaminates the latter figure. The expectation is that

239

households with 15 ampere points would be at the high end of

domestic users and accordingly would be paying on an average higher

electricity charges. It is rather interesting to notice that the rural

households using 15 ampere points reported on an average lesser

amounts of electricity charges than the households using 5 ampere

points (not shown in Table). While it is possible that the high end

users in the rural domestic segment are more economical in their

actual use of electricity, nevertheless the possibility of collusion,

either in meter reading or in billing, cannot be entirely ruled out.

Box-5.1 gives the case of one of the sample villages where such

collusive activity still exists despite reform.

Billing/Payment for the use of electricity

5.19 Frequency of Billing: Though there has been significant improvement

in the billing procedure in the reform period, still 2 to 5 % of the rural sample

households reported about no billing (Table-5.7). There is a significant shift

in the billing system from bi-monthly in the pre reform period to monthly in

the reform period in urban areas. The billing system in rural areas has largely

remained bi monthly in both pre reform and reform periods, but more so in

the latter period.

Box 5.1: Collusion: Who will stop? In one of the sample villages it was found during the household survey that the

meters of most of the houses are stopped for 3/4th of the month and it is operated only towards that part of the month when the meter reader is expected to visit. On

enquiry it was found that the lineman of the erstwhile OSEB used to help the villagers to do the tampering by taking some monetary or non-monetary benefits

(example: free rental house for the line man in exchange for providing free electricity to the owner). Over time, most of the households have learnt to do the

tampering by themselves. The meter reader takes down the deflated reading as the correct reading and the households clear the grossly underestimated dues in time.

240

Table 5.7: Billing frequency as reported by the households Figures in % of responding households

Rural Urban Total

Billing Frequency Pre-reform (Xavier Study)

Reform (CMDR Study)

Pre-reform (Xavier Study)

Reform (CMDR Study)

Pre-reform (Xavier Study)

Reform (CMDR Study)

No Billing 2.86 5.1 Nil 2.3 1.4 1.3 Monthly 16.4 14.1 26.4 68.5 21.5 43.4 Bimonthly 40.0 72.4 46.6 24.1 43.4 45.1 More than Bimonthly 40.7 8.4 27.0 5.1 33.7 10.2 Total 100.0 100 100.0 100 100.0 100.0

5.20 Regularity in Billing: One of the basic objectives of reform is to reduce

the irregularity in the billing. There is a significant achievement of the reform

process in this respect as the irregularity has declined from 50 per cent in the

pre reform period to 11 per cent during the reform period (Table 5.8). Across

rural and urban areas it was found that the irregularity in billing had declined

significantly in urban areas while it remained more or less constant in rural

areas over the years.

Table 5.8: Irregularity in Billing (% of households)

Research Studies Region Pre-reform Reform Rural 18.2 17.0 Urban 21.3 9.7 CMDR Study

(2003) Total - 11.2

Xavier Study (1996) Total 50.3

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5.21 Billing efficiency and consumer perceptions: In order to determine

the efficiency in the reform period billing system, the perceptions of the

people on 5 indicators were collected: correctness in billing, clarity in

billing, ease of payment, timely complaint redressal and satisfactory

solution of the complaint. Table-5.9 gives the extent of incidence of the

perceptions among the households according to 3 possibilities: ‘improved’,

‘deteriorated’ and ‘no change’. The perceptions of people are found to be the

most favourable regarding the payment procedure of the bill. Nearly 74 %

rural and 88 % urban households feel that there has been greater ease of

payment in the reform period. Correctness and clarity in billing comes next

in the ranking and get equal rank in both rural and urban areas, with the

backing of a little more than half of the sample households in both areas.

However, almost 2/3rd (72 %) of the sample households in rural areas

reported that they do not get satisfactory solution to their complaints. In

comparison, about 44 percent of the urban households reported their

satisfaction from the solution to their complaint. It is worth noting that only a

small minority (about 12%) of urban consumers feel that there has been

deterioration with regards to getting a satisfactory solution to their billing

complaints. What comes out as certain is that customer care and grievance

redressal by the DISCOMs in case of complaints related to billing are

perceived to be the least satisfactory by the majority of households in rural

areas. This may be contrasted with the earlier discussion of people’s largely

favourable perceptions about the DISCOMs’ handling of metering-related

complaints. It appears that the reform period system for customer care and

grievance redressal is yet to be developed properly for the different areas of

interface between the consumers and suppliers, particularly in the rural

areas.

242

Table 5.9: Billing efficiency in rural and urban areas

Figures in % of responding householdsIndicators of billing efficiency

Improved Rank Deteriorated Rank No change Rank

Rural Correctness 51.87 2 17.4 3 30.73 4 Clarity 51.43 3 16.52 4 32.05 3 Ease in payment 73.75 1 5.16 5 21.09 5 Timely Complaint 27.97 4 25.55 2 46.47 2 Satisfactory solution 12.79 5 71.64 1 15.57 1 Urban Correctness 66.55 2 14.83 2 18.92 3 Clarity 66.26 3 14.84 1 18.61 4 Ease in payment 87.67 1 3.84 5 8.49 5 Timely Complaint 49.59 4 10.84 4 39.57 2 Satisfactory solution 43.97 5 11.76 3 44.27 1

5.22 Non-payment of bills and disconnection of electricity: Under the new

system it is expected that if there were no payment of the bills, the electricity

connection would be withdrawn. From the field survey it is found that there is

not much difference between rural and urban areas in respect of disconnection

of power due to non-payment of bills. About 9 % of the rural households and

7 % of the households in urban areas reported that their connection was

withdrawn due to non-payment of bills. It seems that the households have

become conscious about the payment of bills in the reform period.

Problems in the Supply of Power

5.23 Power supply and consumers’ perceptions: The problems related

to power supply may be classified as technical and non-technical. The

technical problems are mainly power failures, voltage fluctuation, scheduled

and unscheduled power cuts. The non-technical problems are mainly related

to metering, billing, theft of power, etc. A comparative assessment of rural

and urban consumers’ perceptions indicates that the overall situation of

power supply in urban areas is better than in rural areas during the

243

reform period. More than 80 % to about 90 % of the urban households feel

favorably about the power supply scenario in the reform period, while a

similar sentiment finds expression from 55 % to slightly more than 60 % of

the rural consumers (Table 5.10).

Table 5.10: Consumer perceptions on power supply in the reform period Figures in % of responding households

Rural Urban Problems of power supply I D NC I D NC

Power Failure 59 17 24 82 8 10 Voltage Fluctuation 55 11 34 83 7 11 Un-notified Power cut 61 14 25 90 4 6 Frequent power cut 56 17 27 88 5 7 I=Improved, D=deteriorated, NC= No change

5.23 Power Failure: Power failure is different from power cut. Power

failure occurs due to the problems that are beyond the control of the

supply authorities, e.g. natural calamities (cyclone, flood etc.), over

loading from excess consumption of electricity, theft of electricity, etc.

During the reform period, as judged from the sample households

reporting its incidence, power failure of greater hourly duration

appears to have declined in both rural and urban areas (Table-5.11).

This improvement is more marked in case of the urban areas sampled.

Significantly, about 45% of the urban consumers say that they do not

suffer from power failure at all as against 5% in the pre-reform period

(Xavier Study). Only 13 % consumers in rural areas do not suffer from

power failure during reform period while the same was zero percent

(Xavier Study) during pre-reform period. Though the power supply

situation has improved during the reform period to a great extent,

the incidence of improvement is found to be higher in urban areas

than in the rural areas.

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Table 5.11: Duration of Power Failure in pre-reform and reform periods (Figures in % of sample households reporting for different durations of power failure)

Rural Urban Duration of power

failure Pre Reform Period

Reform period

Pre Reform Period Reform period

CMDR Study, 2003 < 1 hour 18.3 30.4 36.1 35.5 1 - 3 hours 35.4 26.5 32.5 10.5 > 3 hours 46.3 30.5 16.2 9.2 No Power Failure - 12.6 - 44.8 Xavier Study, 1996 No Power Failure 0 5

5.25 Power theft, breakdown of transformers, etc: The major contributing

factors for power failure, as gathered from the consumers themselves, are

frequent theft of power, overloading and poor maintenance of transformers,

falling of trees, etc in rural areas and over loading, theft in urban areas,

besides frequent natural calamities common to the state. Despite the serious

steps taken by the DISCOMs to control the misuse (theft) of power, still

the practice appears to continue on a significant scale in both rural and

urban areas of the State (Box 5.2). The field survey conducted by CMDR

generated a lot of anecdotal evidence about incidents relating to theft of

conductors, the practice of hooking and breakdown of distribution

transformers during both the pre-reform and reform periods. By and large, the

respondents were of the opinion that there has been a significant decline in the

number of incidents involving theft/misuse of power. This general perception

gathered from the field survey matches with the trends observed in the data

obtained from secondary sources. Table-5.11a presents the data relating to the

number of hooking cases detected, length of conductor stolen, number of

transformers burnt, etc. as provided by the DISCOMs to the OERC.

245

5.26 Power cut: Power cut is made deliberately by the authorities when

there is a shortage of supplies or need for repair and maintenance of

transformers, etc. As perceived by the sample households, there appears to

have occurred a marked decline in the duration of power cuts during

summer as well as rest of the year in the reform period for both rural

Performance Indicators 2000-01 2001-02 2002-03 2003-04Number of transformers burnt 6341 6741 4936 4501Cost involved (Rs. Crores) 17.85 18.95 13.96 4.75Length of conductor stolen (Km) 1659.29 1760.26 968.05 423.61Cost involved (Rs. Crores) 4.071 4.351 1.406 0.563Number of hooks detected 83484 68192 309324 126383Number of hooks repeated out of hooks detected 0 0 21701 156Number of connections regularised 29345 75097 109479 54090Number of disconnections made 77277 86572 216860 406702

Table-5.11a: Performance of DISTCOMs in checking theft/misuse of power in Orissa during the reform period

Source: OERC's Review of Performance of DISTCOMs based on data submitted by the companies to the Commission

Box 5.2: THEFT OF POWER IN THE CAPITAL!

About 40-50 unauthorized temporarily constructed houses in the premises of an apex institution in the capital city of Orissa are found to have taken electrical connection through ‘hooking’ from the main lines of electricity provided to the staff quarters. Since the last 10 to 15 years, these households have been using power not only for lighting purposes but also for TV, cooking heaters, electrical grinders and other appliances, etc. Some of them have temporary shops in which they use electricity. The authorities of the Institution have attempted several times to disconnect the illegal connections of the employees but failed. Whenever the authority has taken any initiative towards disconnection, these people have resorted to threatening the authority and other bullying tactic. Consequently, the practice of theft continues and its effect is felt by the consumers residing in the staff quarters who suffer from poor quality of power supply due to over loading. The financial burden of the institution also increases. There is a main meter for the institution for the payment of electricity cost and the illegal users are using the electricity (free of cost) at the cost of the institution.

The theft of power is still continuing almost everywhere which has been stated

by various key informants i.e. Sarapanch (Nayagarh), Sarapanch (Khurda), Councillor (Bhadrak Municipality), Field Officer (Gramyabank, Khurda), Executive officer(Keonjhar,NESCO), Advocate (Bar Association,Nayagarh), OIC Town Police

246

and urban areas. This has been a significant achievement of reform and is

commonly acknowledged. For the reform period, the most common duration

of power cut during summer as well as rest of the year is 1 to 3 hours daily in

rural areas and less than 1 hour in urban areas (Table-5.12).

Table 5.12: Duration of power cut during pre reform and reform periods (Figures in % of sample households reporting for different durations of power cut)

< 1 Hour 1-3 Hour > 3 Hour Not at all Total

Season Pre Reform Period

Reform Period

Pre Reform Period

Reform Period

Pre Reform Period

Reform Period

Pre Reform Period

Reform Period

Pre Reform Period

ReformPeriod

Summer Rural 29.2 27.1 39.1 37.3 28.2 21.1 3.5 14.4 100 100Urban 42.9 39.1 34.0 27.6 18.0 8.2 5.1 25.0 100 100Total 32.2 35.7 37.1 33.2 23.6 14.2 7.1 16.9 100 100Rest of the Year Rural 16.0 24.4 51.5 39.6 25.4 18.9 7.1 17.1 100 100Urban 38.3 35.7 33.9 20.3 16.8 8.0 11.0 36 100 100Total 25.4 32.5 44.2 29.1 20.5 14.2 9.9 24.2 100 100

5.27 The most common duration of power cut is summarized in Table-5.12a

which provides the perception of consumers in the pre reform (Xavier study)

and reform scenario (CMDR study). The duration of power cut was on an

average 1 – 3 hours per day in the pre reform period throughout the year,

while it has improved significantly in the urban areas in the reform period.

Table 5.12a: Most common duration (hours per day) of power cuts during summer as well as rest of year

Research studies Rural Urban

CMDR Study (2003) 1 - 3 hours Less than 1 hour

Xavier Study (1996) 1 - 3 hours 1 - 3 hours

5.28 Alternative sources of power: It is interesting to observe that rural

consumers are increasingly using emergency light during power failures and

power cuts, though the lantern continues to be the source of lighting for

majority of the rural households (Table-5.13). This again is perhaps indicative

247

of a trend that speaks of growing consumer preferences for better quality of

lighting and therefore betters quality of life, even in the rural areas of Orissa.

Table 5.13: Alternative sources of lighting used by consumers during Power Cut/ Power Failure

(Figures in % of responding households)Rural Urban Total

Alternative sources Pre Reform Period

Reform Period

Pre Reform Period

Reform Period

Pre Reform Period

Reform Period

Emergency Light 4.0 12.2 34.6 39.5 19.3 23.8 Lantern 65.9 49.8 30.2 29.7 48.0 41.3 Gas Light 3.1 1.1 10.7 9.7 6.9 4.7 Any other (candle, battery etc) 27 36.8 24.5 21 25.8 30.2 Total 100 100 100 100 100 100

5.29 Voltage Problem: According to the consumer perceptions gathered from

the field survey, the voltage situation in urban areas comes out much better

compared to the position in rural areas during the reform period. Compared to

the 73% of households from the urban sample that report receiving adequate

power supply with normal voltage, it is found that only about half (50.41%)

of the rural households report of receiving normal voltage. The corresponding

percentages of responses were 30% and 34% for rural and urban areas

respectively (XIMB, 1996). Even then, the fact that about 36 % of the

rural households have reported that they suffer from very low voltage

should serve as a cause for concern. In comparison, slightly more than 10 %

of the urban consumers have reported about the low voltage problem.

Table 5.14: Consumer perceptions on voltage quality in reform period

% of households reporting problems related to voltage quality

CMDR Study (2003) Xavier Study (1996) Indicators of voltage quality

Rural Urban Rural Urban Low 35.7 12.3 51 42 High 2.5 1.5 < 1 < 1 Fluctuating 11.4 13.1 15 - 20 20 - 30 Normal 50.4 72.7 30 34 Total 100.0 100.0

Figures in % of responding households

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5.30 Difficulties caused on account of Voltage Problem: Comparatively a

greater proportion (51.4%) of urban consumers than those in rural

areas (37.1%) reported the absence of any type of voltage-related

difficulties in the reform period (Table 5.15). While looking at the

various types of difficulties reported by the consumers on account of

voltage fluctuation, the pattern comes out to be similar in both rural

and urban areas, with the majority complaint being linked to low

voltage in the evening time. The damage to electrical appliances due to

high voltage problem declined significantly from 23 percent in the pre-

reform period to 6 percent during the reform period both in rural and

urban areas. This of course is a healthy sign of the reform process.

Table 5.15: Difficulties reported due to voltage problem in the reform period Figures in % of responding households

Type of difficulty reported by the household Rural Urban Total CMDR Study (2003) Tube lights not working in the evening 42.2 32.0 33.2 Electrical appliances not working at night 11.9 9.1 10.9 Damage to electrical appliances 6.9 5.2 5.9 Accidents caused by high voltage 1.9 2.3 2.1 No problem 37.1 51.4 47.9 Total 100 100 100 Xavier Study (1996) Damage caused to electrical appliances NA NA 22.9

5.31 Management of voltage problem: It seems that the non-use of

electrical equipment in times of voltage fluctuation is the most

common strategy among the rural and urban consumers. However,

during the reform period the use of stabilizer has been reduced to a

large extent and the proportion of consumers not using any type of

protective measure has increased, particularly in rural areas. This gives

a clear impression that there has occurred significant

improvement in the voltage profile during the reform period

(Table 5.16).

249

Table 5.16: Protective measures by households in case of voltage problem Figures in % of responding households

Rural Urban Total

Items Pre

Reform Period

Reform Period

Pre Reform Period

Reform Period

Pre Reform Period (Xavier Study)

Reform Period

(CMDR Study)

Use of Stabilizer 42.2 12.9 27.6 18.6 24 16.0 Use of Capacitor 1.4 1.3 1.6 2.9 NA 1.9 Use of alternative sources of energy 3.4 5.5 6.0 2.4 1 4.3 Non-use of equipment 48.2 48.2 46.6 55.4 19 51.1 No protective measure 4.8 32.0 18.1 20.6 56 26.7 Total 100.0 100.0 100.0 100.0 100.0 100.0

5.32 Electrical accidents: Information about electrical accidents during the

reform period is obtained from the OERC, which has been continuously

monitoring the performance of DISCOMs. Table-5.16a gives the data about

electrical accidents, both fatal and non-fatal, throughout the state. It is a

matter of concern that there is a significantly higher incidence of fatal

electrical accidents to humans in 2003-04 as compared to the previous year.

02-03 03-04 02-03 03-04 02-03 03-04 02-03 03-04 02-03 03-04Human 12 29 7 5 18 18 11 12 48 64Animal 10 11 4 6 12 15 14 13 40 45Human 6 18 1 2 16 13 10 13 33 46Animal 21 - 0 3 1 1 0 1 22 5

ALL ORISSATable-5.16a: Incidence of Electrical Accidents in Orissa during 2002-03 & 2003-04

Source: OERC, Bhubaneswar

Electrical accidents

Fatal

Non-Fatal

CESCO NESCO SOUTHCO WESCO

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V.4 Socio economic Impact of Power Sector Reform: Impact on

Education

Direct impacts

5.33 Study hour duration: The supply of electricity nowadays affects to a

great extent the education of children. If the supply of electricity is interrupted

frequently, particularly during the study hours of children (early morning and

evening) and during examination days, it tends to have a significantly adverse

impact on the education of children. This may be considered as a direct

impact of power sector reform on education. So far as the effect of power

supply on the duration of children’s study hours is concerned, the

majority perception points to an improvement in the current situation

over the pre reform period situation. The perceived improvement

appears to be quite independent of the social status of the sample

households and is relatively more widespread in urban areas than in

rural areas. Table 5.17 provides this information. At the same time, it needs

to be kept in mind that a significant proportion (25 to 36 %) of households

feels that there is still no perceptible change in the situation relating to the

quality of power supply during study hours as compared to the earlier pre

reform years.

5.34 Access to information and e-education: The supply of power to an

area brings with it the potential to increase consumers’ access to e-education

and e-information. This helps in particular the children to increase their

educational standard to great extent. The overwhelming majority of rural

households sampled perceive no change in the situation relating to access

to computer and Internet in the reform period (Table-5.17). On the other

hand, a significant % of urban households, particularly from the

privileged category, do feel that there has been improved access to e-

education in the reform period.

251

Indirect Impacts

5.35 Educational performance of children: In a general way, the standard

of educational performance of children is likely to be closely linked with the

duration of study hour. If the study hour is affected on account of poor power

supply, the performance level is likely to deteriorate. The power sector reform

in this case affects education indirectly. A majority of sample households

(over 60 % in rural areas and about 50 % in urban areas) failed to

perceive any type of impact on the educational performance of their

children resulting from the changed power supply situation in the reform

period. However, the urban bias of the reform impact appears again in

the form of a relatively greater percentage of urban households opining

that compared to the pre-reform period the reform-period educational

performance of children has improved.

5.36 Attendance of evening classes (Girl/female children): Generally

students attend the evening classes (either tutorial or coaching, dance, music,

etc) because the regular schooling hours is during the daytime. In a situation

of regular and frequent interruptions in power supply during evening hours,

parents would naturally hesitate to send their children to such classes. It is

found that irrespective of the social category, majority of the parents in

urban areas (more than 50% to 76 %) do perceive the current situation

conducive for allowing their daughters to attend evening classes. This

feeling is found to be much less spread in rural areas. Also a significant

proportion of less privileged caste households particularly in rural areas does

not feel any change in the attendance of evening classes by girl children

during the reform process. However, it should be kept in mind that there

might be limited opportunities for children in rural Orissa to avail themselves

of facilities offered by evening classes.

252

Table-5.17: Consumer perceptions about reform’s impact on education of children

Figures in % of responding households Rural Urban

Privileged Less Privileged Privileged Less PrivilegedImpact Indicators

I D NC I D NC I D NC I D NC Duration of Study Hours (early morning & evening hours)

47 18 36 47 17 36 58 13 28 58 17 25

Access to information and e-education (TV, Computer & Internet)

10 0 90 4 0 96 45 5 50 32 8 60

Educational performance of children

28 9 63 26 14 60 37 13 49 35 15 50

Conduciveness of situation for girls to attend evening classes

35 16 49 26 23 52 76 1 23 51 3 46

Note: (i) I = Improved; D = Deteriorated; NC = No Change (ii) Figures may not add up horizontally to 100 for different social categories because of rounding up V.5 Socio Economic Impact of Power Sector Reform: Impact on

Health

Direct impact

5.37 Diagnostic tests: Electricity has a crucial role to play in the

provisioning of health care services. The machines/equipment used for

different types of diagnostic tests and operations depend largely on

continuous and uninterrupted power supply, which is a basic objective of

power sector reform. More than 50 % households in rural and more than

80 % in urban areas are reported to have perceived that there is an

improvement in the situation relating to the timely conduct of diagnostic

tests of different types in the reform period (Table 5.18).

5.38 Health care of children and sick: Not only different diagnostic tests

but the health care of children and sick persons in the households are also

253

affected by the quality of power supply. (For instance, the sick persons, old

persons and persons with hypertension etc require continuous fans and AC

during summer, which require un-interrupted power supply.) It is found that

about 50 to 57 % of households in the total sample perceive that there has

been improvement in the health care status in households due to

improvement in power supply in the reform period. At the same time,

more than 40 % of the households do not feel any change in the situation.

Across social categories, it is observed that a relatively larger percentage of

privileged group households give a favorable opinion about the impact of

reform.

Indirect Impact

5.39 Health status of women: Women in general, and working women and

rural women in particular, get very little time to take care of their own health.

The use of electrical appliances in domestic chores is expected to reduce

drudgery and improve the health status of women along with the overall

quality of life enjoyed by them. Since the use of such appliances is linked to

the quality of power supply, the issue of the impact of reform in the power

sector again becomes relevant. Barring the urban households belonging to the

privileged category, the majority perception in all other categories is that there

has been no change in the health status of female members in the household

during the reform period. Nevertheless, it is encouraging to note that close

to one-third of sample households cutting across social categories as well

as the rural-urban division provides the perception that points to a likely

positive impact of reform on health status of women.

254

Table-5.18: Consumer perceptions about reform’s impact on health services and health care in households (Figures in % of responding households)

Rural Urban

Privileged Less Privileged Privileged Less PrivilegedImpact Indicators

I D NC I D N

C I D NC I D NC

Timely conduct of diagnostic tests 53 8 39 50 7 43 87 1 12 71 2 27

Health care of children and sick in households

53 4 43 49 4 46 57 2 41 51 4 45

Health status of women members in households

34 19 47 32 13 54 42 20 38 37 17 46

Note: (i) I = Improved; D = Deteriorated; NC = No Change

V.6 Socio Economic Impact of Power Sector Reform: Impact on

Women

Direct impact

5.40 Time saved from domestic work: About 45 % (less privileged) to 50 %

(privileged) of the households in rural and 52 % (less privileged) to 63 %

(privileged) households in urban areas are reported to have perceived that

their time used for domestic work has reduced during the reform period as

compared to the pre reform period (Table 5.19). It appears that the reduced

drudgery of work burden for women in the reform period has a larger

incidence among urban households and those belonging to the privileged

social category.

5.41 Leisure time: About 55 to 67 % households in rural and 66 to 69 %

households in urban areas have reported that their leisure time has increased

during the reform period as compared to 10 years back. The availability of

leisure time appears to be more among women belonging to the

privileged category households in urban areas than that in rural areas

and women in less privileged households.

255

Indirect impact

5.42 Productive utilization of extra time: It is observed that 90 % to 93 %

of rural households and 66 % to 73 % urban households are not able to

productively utilize the extra time gained on account of reduced work

burden on the domestic front. It is possible that there may be a dearth

of opportunities for women to use their time gained for productive

activities, particularly in the rural areas (Table 5.19).

Table-5.19: Consumer perceptions about reform’s impact on women (Figures in % of responding households)

Rural Urban

Privileged Less Privileged Privileged Less PrivilegedImpact Indicators

I D NC I D N

C I D NC I D NC

Time spent for domestic work 20 50 30 24 45 31 16 63 21 18 52 30

Leisure time 57 12 31 55 13 32 69 15 16 66 16 18 Time used for skill building 9 1 90 6 1 93 32 2 66 26 1 73

Time used for income generation 11 1 88 10 1 89 16 4 80 15 4 81

Safety and security of women 20 17 63 18 23 59 32 33 35 35 28 37

Note: (i) I = Improved; D = Deteriorated; NC = No Change (ii) Figures may not add up horizontally to 100 for different social categories because of rounding up

5.43 Safety and Security: More than 50 % (59 to 63 %) of households in

rural areas and 35-40 % households in urban areas reported that there is no

change in so far as the security of women is concerned during reform period.

In fact, among the urban households sampled, the opinion about insecurity of

women is almost equally divided as to whether there has been improvement,

deterioration or no change in the situation in the reform period.

256

V.7 Impact of power sector reform on livelihood

5.44 Employment: Improved power supply in the reform period is

supposed to generate rural employment in the cottage, tiny and small-scale

industries, such as flour mills, rice mills, textile units, appliqué and other craft

centres, tailoring units, etc that are located in villages and their vicinity. In

both rural and urban areas, households belonging to the privileged category

generate a majority (> 50 %) opinion that there has been increased

employment of male workers in the cottage and small-scale industry sector

during the reform period (Table-5.20). The same opinion comes from the

perceptions of a significant percentage of the sample households belonging to

the less privileged category in both rural and urban areas.

Table 5.20: Employment in cottage, tiny and small scale industries Less Privileged Privileged

I D N C I D N C

Rural Male 45.8 5.6 48.6 52.3 5.5 42.2 Female 23.4 7.3 69.3 33.2 8.0 58.7 Total 35.0 6.5 58.5 43.4 5.1 51.5

Urban Male 49.8 2.1 48.0 60.4 2.1 37.5 Female 43.3 5.5 51.2 54.2 4.4 41.4 Total 44.2 4.2 51.6 56.5 3.2 40.3

I=Increased, D-Decreased, NC-No Change

V.8. Impact of Power Sector Reform on Consumption Pattern of the

households

5.45 In view of the hike in tariff, it is expected that there may be a change in

the consumption pattern of the household and due to this change, there is

possibility of foregoing some of the family expenditures The majority of the

perceptions in respect of this aspect indicates that there is an increase in the

household spending on consumption but no expenditure is postponed due to

the hiked rate of tariff of electricity (Table 5.21). This provides a clear idea

257

that in view of the improved power supply the consumers are willing to pay

for electricity uses without distorting their consumption pattern.

V.9 Impact of Power Sector Reform on Agriculture

5.46 Agricultural productivity: The majority of rural households surveyed

(nearly 85 %) perceived no change in the productivity of agriculture during

the reform period as compared to its pre reform position. Considering the very

low consumption of electricity in agriculture in Orissa, it is almost a foregone

conclusion that there is very limited scope for power sector reform to make its

impact significantly felt on the productivity level.

5.47 Cold storage facility: Has the better power supply scenario in the

reform period induced addition to cold storage facility for agricultural

produce? The rural households surveyed almost near unanimous in their

opinion that there has been no change in the availability of cold storage

facility in the reform period. However, a small minority of 17 % of the

privileged urban households felt that there has been a reform-period

improvement in the storage situation in urban areas.

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Summary statement of the perceptions of HHs on impact indicators

5.48 The perception of households (HHs) on impact indicators discussed above are summarized in Table 5.21in amore descriptive way. Table 5.21 Summary statement of the perceptions of HHs on impact indicators

Majority Perception Rural Urban

Impact Indicators Privileged Category

Less Privileged Category

Privileged Category

Less Privileged Category

Impact on Education Power Supply during Study Hours I I I I Access to Information and E-education NC NC I NC Average Per Performance Level of Children NC NC I I Attendance of evening classes by girls NC NC I I Impact on Health Timely Conduct of Diagnostic Tests I I I I Health care of sick and children I I I I Health status of Women I NC I I Impact on Women Time saving by women from Domestic work I I I I Leisure time available to women I I I I Skill-building and income generating activities NC NC NC NC Safety and Security of women NC NC NC NC Impact on Consumption Pattern Family Consumption expenditure I I I I Foregone or postponement of familyexpenditure NC NC NC NC Impact on agriculture Impact on productivity of agriculture NC NC - - Impact on storage NC NC - - Impact on Employment Employment in cottage, tiny and small scale industries Male Employment I NC I I Female Employment NC NC I NC Total NC NC I NC Impact on Income Generation Participation of family members in incomegenerating activities Male Employment I I NC I Female Employment I I I I I = Improved, NC = No Change, D=Deteriorated

259

V.10 Consumers’ Willingness to Pay at a Hiked Rate

5.49 Willingness to Pay: The present tariff rate seems to put financial

burden on the consumers to such an extent that about 73 % rural and 51 %

urban households of the total sample are not willing to pay any extra rate for

electricity over and above the present tariff. However, it is interesting to note

that with a rise in the level of education consumer’s willingness to pay

increases. It seems higher level of education and urbanization enhance the

willingness of the consumers to pay more towards electricity charges if they

are assured of better and regular supply of electricity. This can be seen from

Table 5.22.

Table 5.22: Consumer’s Willingness to Pay for Electricity at a Hiked Rate of Tariff by Levels of Education

% of Households revealing willingness to payLevels of Education Nothing 5 % more 10 % more

Rural Illiterate 86.97 8.76 4.27 Below Matriculation 73.91 19.04 7.05 Above Matriculation 58.95 24.53 16.52 Total 73.28 16.98 9.74 Urban Illiterate 62.83 28.26 8.91 Below Matriculation 51.62 31.48 16.90 Above Matriculation 33.94 27.90 38.16 Total 51.46 26.78 21.76

V.11 Analysis of data from Commercial & Industrial (small-scale)

consumers

5.50 Sample profile: The survey of commercial and industrial units for the

present impact assessment study covered a total number of 212 units

belonging to the small-scale segment of the commercial and industrial

category of electricity consumers in Orissa. The number of units sampled in a

survey area was largely determined by the presence of such units in that

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particular area and the variety. Selection of the sample units was largely

purposive with a view to capture as much as possible the different types of

commercial and industrial activities present in a location. For the 8 districts

sampled, with the exception of the Khurda district, each district has about 20

to 30 sample units belonging to the commercial and small-scale industrial

consumer categories. The size of the sample (62) for Khurda district is

relatively large because the State capital with a large number of commercial

enterprises falls in this district. Table-5.23 gives the district wise distribution

of the sample units along with their metering status.

Table 5.23: District wise status of Metering of sample units belonging to

commercial and industrial category

Districts No. of

metered units

Units with Working Meters

as % of Total Metered Units

No. of Unmetered

units

Total sample units

Keonjhar 18 100 9 27 Bhadrak 25 100 2 27 Sambalpur 21 100 3 24 Angul 18 100 2 20 Khurda 60 100 2 62 Nayagarh 19 100 1 20 Raydgada 20 100 0 20 Ganjam 22 100 0 22

Total 203 100 19 222 5.51 Supply of electricity: There appears to be significant regional variation

in the power supply position as far as its adequate availability to the

productive units under consideration is concerned. Almost one third of

the sample units seem to have problems with the adequate availability

of electricity for their productive purposes (Table-5.24). The

percentage of units reporting inadequate supply of electricity is as high

as 71% for Keonjhar district.

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Table 5.24: District wise status of Supply of Electricity to commercial and industrial users

Districts

Total Units

Units reporting adequate supply of

electricity (% to total)

Units reporting inadequate supply of

electricity (% to total)

Keonjhar 24 29.2 70.8 Bhadrak 27 55.6 44.4 Sambalpur 21 61.9 38.1 Angul 20 85.0 15.0 Khurda 61 91.8 8.2 Nayagarh 20 75.0 25.0 Raydgada 20 65.0 35.0 Ganjam 19 68.4 31.6 212 70.3 29.7

5.52 Impact of reform on productivity/efficiency/profitability: So far as the

impact of reform on the productivity, efficiency and profitability of the

commercial and industrial consumers is concerned, most of the sample units

reported that the promised benefit of power sector reform relating to adequate

supply of quality power is yet to reach them in a significant way. They

complain that power problems like irregularity in power supply and poor

quality of voltage still exist and continue to affect adversely the functioning of

the units. The problem is particularly severe during summer time. District

wise, the units located in the northern region (Keonjhar and Bhadrak) come

out as the worst sufferers of continuing power sector problems. At the same

time, however, there appears to be a growing realization among the sampled

units that the situation may be turning for the better.

It is significant and a cause for concern that in contrast to the generally

favourable perception of household consumers regarding the reform-

period power supply situation and also in contradiction with the

improved power supply scenario brought out by macro performance

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indicators, there is a general feeling of discontent among the commercial

and industrial category of users about the adequate availability of quality

power, particularly among units located in the relatively backward

districts of the State.

5.53 Alternative sources of power and associated cost: Table-5.24

presents the other-than-electricity sources of power used by different

categories (connected load wise) of commercial and industrial units and the

average cost per month associated with such use. In the case of diesel

generators, larger units are seen to have a relatively lesser need to use them as

compared to the units with small loads, since the average hours of use of such

generators per month decline as one moves from units with small loads to the

more power-intensive units. This appears to be a case of the regressive

impact of power sector reform on commercial and industrial users. The

average monthly cost on this source of power is higher for larger units, but

one cannot rule out the possibility that when estimated relative to their

respective turnovers, the financial burden on the smaller units would be

disproportionately higher. Taking all units using diesel generators together,

the average monthly cost comes to Rs.5614, which is a significant amount.

For units using gas as the alternative power source, the average monthly cost

is considerably lower (Rs.745).

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Table 5.24 a: Alternative Sources of Power / Stand by Facilities and the associated cost for commercial and industrial users of different capacity size (KW terms)

Capacity wise User Category Type of Alternatives

<=1 KW >1 KW TO <=5 KW

>5 KW TO <=10 KW

Above 10 KW Total

No.of Units 7 9 7 17 40 Avg Cost (Rs. Per month) 3078 2650 8597 6789 5614

Diesel Generator

Avg Hrs per Month 61 55 31 39 45 No.of Units 28 18 3 0 49 Avg Cost (Rs. Per month) 369 1290 733 0 745 Gas

Avg Hrs per Month 38.2 41.7 72.7 0 42.3 No.of Units 0 0 0 2 2 Avg Cost (Rs. Per month) 0 0 0 335 335 Solar

Avg Hrs per Month 0 0 0 7.5 7.5 No.of Units 25 14 3 2 44 Avg Cost (Rs. Per month) 757 2005 1133 500 1141 Others

Avg Hrs per Month 40.0 46.3 8.7 7.0 37.1 No.of Units 100 59 28 34 222 Avg Cost (Rs. Per month) 867 1773 5060 5421 2268 Total

Avg Hrs per Month 42.2 45.6 37.8 31.2 40.9 5.54 Customer care and grievance redressal: With the exception of the

units coming under CESCO, the majority of the consumer units served by the

other 3 DISCOMs complain of poor customer care and un-satisfactory

solution to grievances. Again, the units coming under NESCO turn out to be

the worst sufferers. Most of the complaints of the industrial units relate to the

improper functioning of meters and the incorrect reading of meters.

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CONCLUSION

SUMMARY

In the first two chapters of my thesis, I have discussed the theoretical

framework of reforms and its necessity for timely adoption. The main aim of

this thesis is to bring out an ideal framework for all those state utilities

aspiring to unbundle their vertically integrated utility. The earlier Electricity

Act. 1909 failed to deliver the results in terms of their financial viability.

Power sector investment has always been dependent on budgetary support and

external borrowings. Electricity Act. 2003 was enacted with a view to de-

regularizing the vertically integrated utilities, opening the field of generation

and distribution to private players and introduction of power trading system.

To achieve a robust GDP growth of 8 per cent per annum, the growth rate of

power sector is prescribed to grow over 10 per cent per annum. Initiatives

were taken in the chief minister’s conference on Common Minimum National

Action Plan for Power (CMNPP) convened by Prime Minister in 1996 which

ushered in the comprehensive reforms program for power sector including

reforms in distribution sector. The results were visible in the Ninth Plan (1997

– 02) with an addition of 19,015 MW from the preceding plan period. The

reform policy also allowed private sector to set up companies with 100%

foreign participation and with a maximum 4:1 debt equity ratio. The return on

foreign equity was protected in foreign currency and a number of tax

concessions were extended to woo the investors.

I have analyzed the growth of power sector in detail. The way the power

sector has performed in the past several years across several plan periods has

been supplemented with necessary tables and graphs. In spite of many

rewarding initiatives the participation from the private players has been

considerably low as compared to public sector participation. One of the

reasons may be attributed to the lack of comprehensive fuel supply agreement

265

(FSA). The IPPs insist that the penalty for supply interruptions should cover

the loss of revenue (Fixed cost component of tariff) attributable to the default

in fuel supply. Penalty could be on the basis of the additional cost incurred in

procuring fuel from alternate sources but railways contend that it should be on

the value of the fuel not on supplied.

In the subsequent chapter, I have discussed the success of global players in

power sector reforms which includes nations falling in European Union, USA

and Latin American countries and few other successful reform programs

which acted as the precursor to India’s reforms initiatives. During my course

of research the California power crisis happened and I’ve discussed it at

length. In India, Orissa became the pioneer state to adopt the reform program

way back in 1996 which had set a mile stone in the field of power generation

and distribution. Other states like Andhra Pradesh and Delhi soon started the

calibrated reforms initiatives after examining the fault line in the Orissa

model of power sector reforms. During my analysis I found to conclude that

the reform processes which were extremely successful abroad is not viable

because of several underlying reasons like: High AT&C losses, concentric

area development, ability to pay, willingness to pay and above all the

excessive political interference from the successive state governments. Power

has always been subsidised by several state governments but government fails

to make the payment to the state run SEBs.

Chapter IV deals with the enactment of a new Electricity Act. 2003 and

implementation of Montek Singh Ahluwalia Report recommended the ways

and means for one time settlement of outstanding dues of SEBs to CPSUs.

The World Bank’s model on structural reforms in power sector has been

discussed in detail. It is the prerogative of the different state governments to

adopt the most suitable one as per their viability and need. This chapter also

traces the changes in the legal provisions governing electricity power tariffs

and discusses the processes and methodologies adopted over time for tariff

setting till the formulation under Section 178 of the Electricity Act, 2003,

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which may be called the Central Electricity Regulatory Commission (Terms

and Conditions of Tariff) Regulations, 2004. A broad comparison has been

made over the existing tariff structure vis-a-vis availability based tariff

(ABT). An in-depth analysis has been made to find out the mechanism of

calculation of cross-subsidy put forth by different agencies working in this

area. The financial crisis besetting the Indian power sector has always been an

issue of great concern for the planners and experts but evolving an audit i.e.

Energy audit mechanism was never introduced to the system because it may

lead to some path breaking findings such as excessive estimation of T&D

losses, High Transmission (11KV & above) losses, unwillingness of utilities

for effective metering, indication of significant commercial losses in HT

level, etc.

Chapter V deals with the appraisal of Orissa’s reforms experience and its

failure to become a financially profitable organization as against predicted by

consultants who drew up this pragmatic reform model against a staggering

Rs.306.422 crores as consultancy fees from Britain's Department for

International Development (DFID). Consultants includes KPMG – Pre-reform

Consultancy, Credit Suisse First Boston – privatization consultancy, Merz

McLellan & Seaboard International – Project management consultancy, Price

Waterhouse Coopers – other consultancy, has raised many unanswered

questions on the efficacy and practicability of their consultancy. A detailed

study has been made after examining its fault lines, and suggestions have

been placed to improve its performance. During the course of my research,

GRIDCO witnessed its turnaround in the A.Y 2003 – 04 and predictions are

strong that complete turnaround after writing off previous losses will be

possible in the year 2008 – 09. A complete case study has been prepared in

this regard and it has received appreciation from several quarters after its

publication in the Journal of Power Professionals “HORIZON”, Oct – Dec,

2005 Vol. 7 No.1. An attempt has been made to compare the financial

performance of Orissa with Andhra Pradesh, though AP started its reforms

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process much later than the state of Orissa. Orissa has become a model state

among its counterparts as far as power sector reform is concerned and its

successful turnaround under Mr. Suresh Chandra Mahapatra, IAS the then

CMD of GRIDCO has again reaffirmed the faith in a person with dedication

towards duty and transparent functioning.

In the concluding chapter “Socio economic impact assessment of power

sector reforms – An impact analysis” an attempt has been made to develop a

general micro level perspective about the effect of reform on different user

categories on the basis of various impact parameters. The data collected from