Know Your Power

A Citizens’ Primer on the Electricity Sector

3rd Revised Edition

January 2019

Sreekumar Nhalur | Ashwini Chitnis | Saumya Vaishnava | Ashwin Gambhir

About Prayas

Prayas (Initiatives in Health, Energy, Learning and Parenthood) is a non-profit organisation based in Pune, India. Members of Prayas are professionals working to protect and promote the public interest in general, and interests of the disadvantaged sections of society, in particular. Prayas (Energy Group) works on theoretical, conceptual, regulatory and policy issues in the energy and electricity sectors. Our activities cover research and intervention in policy and regulatory areas, as well as training, awareness, and support to civil society groups. Prayas (Energy Group) has contributed to the development of energy sector policy as part of several official committees constituted by Ministries, the erstwhile Planning Commission and NITI Ayog and advisory committee of many Regulatory Commissions. Prayas is registered as a SIRO (Scientific and Industrial Research Organisation) with the Department of Scientific and Industrial Research, Ministry of Science and Technology, Government of India.

Prayas (Energy Group)

Unit III A & B, Devgiri, Kothrud Industrial Area,

Joshi Railway Museum Lane, Kothrud, Pune 411 038 Maharashtra

Phone: 020 – 2542 0720

Email: energy@prayaspune.org Website: http://www.prayaspune.org/peg

Suggested citation: Prayas (Energy Group). (2019). Know your power: A citizens’ primer on the electricity sector

1st Edition: May 2004

2nd Edition: July 2006

Lead authors: Sreekumar N, Girish Sant

3rd Revised Edition: January 2019

Lead authors: Sreekumar Nhalur, Ashwini Chitnis, Saumya Vaishnava, Ashwin Gambhir

Data and production support: Shilpa Kelkar, Manabika Mandal

Illustrations: Manjiri More, Sandeep Deshpande, Gayatri Joag

E-Publication: February 2019 (Conversion by Textsoft Solutions Pvt Ltd)

Cover Design, Layout and Printing: Mudra, 383 Narayan Peth, Pune. Email: mudraoffset@gmail.com

Copyright: Any part of this report can be reproduced for non-commercial use without prior permission, provided that Prayas is clearly acknowledged, and a copy of the published document is sent to Prayas.

For private circulation only.

Figures

Figure 1.1: Correlation between per-capita energy consumption and HDI

Figure 1.2: Large number of people depend on non-commercial sources of energy such as smoky chulhas

Figure 1.3: Energy supply - commercial and non-commercial in 2015

Figure 1.4: Energy use in 2015

Figure 1.5: The energy tree

Figure 1.6: Two-way relationship between electricity and development

Figure 1.7: What is the use of electricity: Faraday with new born child

Figure 2.1: A simple circuit

Figure 2.2: Model of an atom

Figure 2.3: Water tank with tap closed

Figure 2.4: Water tank with the tap open

Figure 2.5: Immersion water heater and LED lamp

Figure 2.6: Direct Current and Alternating Current

Figure 2.7: AC generator

Figure 2.8: Voltage produced in the coil at different positions of the rotation

Figure 2.9: Friends passing books

Figure 2.10: Two kinds of power in an AC circuit

Figure 2.11: Pushing a ball along an incline

Figure 2.12: Voltage and current waves in an AC power system

Figure 2.13: Three phase system

Figure 2.14: Single phase system analogy

Figure 2.15: Three phase system analogy

Figure 2.16: Schematic diagram of a power system

Figure 3.1: Coal based generating unit schematic

Figure 3.2: Combined cycle gas power plant

Figure 3.3: Wind turbine schematic

Figure 3.4: Schematic of a rooftop PV system

Figure 3.5: Hydro station schematic

Figure 3.6: 765 kV transmission tower

Figure 3.7: Transmission substation

Figure 3.8: Distribution lines under construction; Distribution transformer

Figure 3.9: Changing pattern of electricity consumption

Figure 3.10: Increasing electricity accidents

Figure 3.11: Hourly load curve

Figure 3.12: Load duration curve

Figure 4.1: Power theft by tapping the power line

Figure 4.2: Schematic of energy flows in a state

Figure 4.3: AT&C loss calculation for a DISCOM

Figure 4.4: Electricity regions in India

Figure 4.5: Grid operational hierarchy

Figure 4.6: Generation station control centre

Figure 4.7: The tandem cycle to explain coordinated grid operation

Figure 4.8: Grid collapse

Figure 5.1: Institutional structure of the Indian power sector before reforms

Figure 5.2: A typical state electricity sector

Figure 5.3: Three-tiered grievance redressal mechanism

Figure 5.4: Captive generation capacity over the years (MW)

Figure 5.5: Volume of electricity traded via inter-state traders and power exchanges

Figure 5.6: Coal production in India in 2016-17

Figure 6.1: Tools introduced in this chapter

Figure 6.2: NPV of Design A and B at different discount rates

Figure 6.3: Changing total costs of the three generation plants

Figure 6.4: Total cost and levelised cost for Plant B

Figure 6.5: Lending sources for 125 thermal projects that were approved between 2005 to 2015

Figure 6.6: Ash pond and transportation of ash

Figure 7.1: Electricity and money flows in a state level electricity system

Figure 7.2: Tariff determination process for a DISCOM

Figure 7.3: Indicative timeline for Tariff process for a financial year ‘t’

Figure 7.4: Major steps in tariff determination

Figure 7.5: Level of cross subsidy included in the tariff for different consumer categories

Figure 7.6: Movement of tariff in Maharashtra from 1975 to 2003

Figure 7.7: Average electricity tariff charged to farmers and the percentage of metering in some states

Figure 7.8: Energy charge (Rs/kWh) for Low Tension (LT) residential consumers for MSEDCL, Maharashtra

Figure 7.9: Energy charge (Rs per kWh) for Low Tension (LT) residential consumers in Madhya Pradesh

Figure 8.1: Planning for the electricity sector - A simple schematic

Figure 8.2: Schematic of IRP process for a state or distribution company

Figure 8.3: Comparing CEA demand projections and actual demand growth

Figure 9.1: Schematic representation of a vertically integrated utility

Figure 9.2: Public financial institutions financing stressed and non-performing assets

Figure 9.3: Generation capacity-fuel mix 1990 and 2018

Figure 9.4: Generation capacity-ownership mix in 1990 and 2018

Figure 9.5: Generation-fuel mix 1990 and 2018

Figure 9.6: Generation-ownership mix 1990 and 2018

Figure 9.7: State level power sector after the E Act

Figure 9.8: Electricity consumption mix 1990 and 2017-18 (estimated)

Figure 10.1: Rural electrification over the years

Figure 10.2: MSEDCL DISCOM sales which can cost-effectively move to rooftop solar

Figure 10.3: Carriage and content separation in electricity

Figure 10.4: Issues with quality of supply

Figure 10.5: Changes and challenges in distribution sector

Figure 10.6: Changing nature of the DISCOM

Tables

Table 2.1: Understanding the simpler units of measurement

Table 2.2: Counting big, counting small

Table 2.3: List of units of measurements

Table 3.1: Key information for different generation options

Table 3.2: Major HVDC links and inter-regional transfer capacity in 2017

Table 3.3: Details of transmission lines

Table 3.4: Typical voltage levels for generation, transmission and distribution

Table 3.5: Distribution lines: Typical parameters

Table 3.6: Breakup of consumer numbers, connected load, consumption and revenue

Table 3.7: Appliances used by different categories of consumers

Table 3.8: Small house electricity consumption

Table 3.9: Big house electricity consumption

Table 3.10: Typical supply standards

Table 3.11: Typical service standards

Table 3.12: Hourly load data

Table 3.13: Typical appliance consumption

Table 4.1: Calculation of T&D losses for a state

Table 4.2: Typical Transmission and Distribution efficiency indicators

Table 4.3: Organisations involved in transmission system

Table 4.4: Merit order for select stations in Andhra Pradesh

Table 5.1: Installed generation capacity as on March 2018 (in MW)

Table 5.2: Transmission ownership as on March 2018

Table 5.3: Some major players in the manufacturing of power equipment

Table 6.1: Design options for consideration

Table 6.2: Payback period and life of the asset

Table 6.3: Accounting Rate of Return

Table 6.4: Net Present Value (NPV)

Table 6.5: Benefit - Cost Ratio

Table 6.6: Internal Rate of Return

Table 6.7: Annual savings from Design A and Design B (in Rs crore)

Table 6.8: Net Present Value (in Rs crore) at discount rates of 2%, 3.3% and 4%

Table 6.9: Economics of Design B with and without a loan

Table 6.10: Comparing annual costs of generating plants

Table 6.11: Linkage between PLF and cost of power generation

Table 6.12: Discount rate and life cycle costs (Rs crore)

Table 6.13: Levelised Cost for the plants

Table 6.14: Capital cost of Plant B

Table 6.15: Revenue requirement for generation plant

Table 7.1: Percentage split of costs of Maharashtra DISCOM FY 2017-18

Table 7.2: Estimation of metered sales

Table 7.3: Estimation of unmetered sales and T&D losses

Table 7.4: An example of power procurement planning

Table 7.5: Illustrative Annual Revenue Requirement (ARR) of a distribution company

Table 7.6: Illustrative calculation of category-wise revenue that can be recovered at a given tariff

Table 7.7: Illustrative calculation of consumer category wise Average Billing Rate (ABR)

Table 7.8: Government subsidy to agricultural consumers

Table 7.9: ARR as approved by the commission and actuals claimed by the DISCOM

Table 7.10: Sales of distribution company

Table 7.11: Proposed costs for the generator

Table 7.12: Specifics of a 500 MW power plant

Table 7.13: Proposed and approved parameters of generating station

Table 7.14: Actuals as claimed by the generating station

Table 7.15: Restatement of agricultural electricity sales and distribution loss

Table 9.1: Loss reduction programmes

Table 9.2: Major changes in the electricity and related sectors since 1990

Boxes

Box 1.1: The thousand lens - have a look to understand India better

Box 1.2: The 1000 lens: Have a look to understand the energy use better

Box 1.3: Policy action on electricity and development in different countries

Box 2.1: Atoms and electrons

Box 2.2: How to read a name plate?

Box 2.3: Battle of the currents

Box 2.4: 50 Hz vs 60 Hz

Box 2.5: What is ‘load’ and what are the types of load?

Box 2.6: Benefits of a good power factor

Box 3.1: How to set up a solar rooftop PV system?

Box 3.2: Hydro generation: Types of turbines and calculation of power generated

Box 3.3: Big hydro projects: Some controversial issues

Box 3.4: Agriculture water pumping as a major electricity end use

Box 3.5: A parallel to road traffic

Box 4.1: What is Merit Order?

Box 4.2: Ride a cycle to learn how the power system works

Box 4.3: Grid collapse, blackout and brownout

Box 5.1: The Electricity Act (2003)

Box 5.2: A timeline of the Indian power sector

Box 5.3: Typical organisation of a DISCOM

Box 5.4: Input-based distribution franchisees

Box 5.5: Non-traditional consumers

Box 6.1: Time Value of Money

Box 6.2: Cost of Conserved Energy

Box 6.3: Running a conventional power plant

Box 6.4: Who is financing our thermal power projects?

Box 6.5: Life of a project

Box 6.6: Things to know

Box 6.7: Hidden costs: Externalities

Box 7.1: Performance based regulation: The experience in the UK

Box 7.2: Unmetered sales and T&D losses

Box 7.3: Power procurement planning

Box 7.4: Annual Revenue Requirement and tariff determination

Box 7.5: Revenue gap

Box 7.6: Transmission Tariff

Box 7.7: Stylised example for generation tariff

Box 7.8: Stylised example for generation tariff … continued

Box 7.9: Tariff for renewable energy projects

Box 8.1: Brief history of Integrated Resource Planning

Box 9.1: The Enron story

Box 9.2: Competitive bidding and compensatory tariff

Box 10.1: Carriage and content separation

Box 10.2: Smart grid, smart meters

Box 10.3: In the long run, how much energy do we need?

Preface to the 3rd Revised Edition

We published Know your power: A citizens’ primer on the electricity sector in 2004. This was in response to the successful sessions on the basic concepts of the Indian electricity sector in our many workshops. A revision was published in 2006, a Kannada translation in 2008 by the Karnataka Electricity Regulatory Commission, and a Marathi translation in 2009 by Prayas with support from the Maharashtra Electricity Regulatory Commission.

Over the years, we have distributed more than 4000 copies of the Primer to government officials, consultants, teachers, students and civil society groups. During this time, we have published many other guides covering topics like addressing electricity complaints, increasing regulatory engagement and using tools like the Right to Information Act. But among our publications, the Primer stands out for providing a comprehensive overview of the technical, economic and institutional aspects of the Indian electricity sector in an accessible manner. It is interesting to note that there is high demand even today for the 2006 Edition of the Primer, even though there have been many major changes in the sector since then. The Primer has played a significant role in our efforts to reach out to officials and civil society groups and has provided them an in-depth understanding of the sector.

Prayas (Energy Group) has also undergone major changes since 2006. From a group with few researchers and publications, we have grown in size and spread, with more than 300 publications. Girish Sant, the co-founder of Prayas (Energy Group) and a lead author of the Primer, sadly passed away in 2012. We also record the sad demise of Professor Amulya Kumar N Reddy and Dr Krishna Prasad who had offered their valuable insights during the writing of the 1st Edition of the Primer. Pallavi Apte, one of the artists who helped with the previous editions, also sadly passed away during this time.

We are happy to present this completely revised edition of the Primer. We have retained the basic structure and style of the previous editions, but all chapters have been completely revised based on feedback and developments in the sector. Chapter 1 locates the electricity sector in the broader social context; Chapters 2, 3 and 4 explain the important technical aspects of the sector; Chapter 5 introduces the major actors in the sector; Chapter 6 and 7 cover the key aspects of sector economics and tariffs; Chapter 8 is on planning; and Chapter 9 gives a brief overview of the reforms in power sector since 1990. Chapter 10 is a new addition, on the challenges of energy transition. Chapter 11 summarises the observations and suggests a framework for citizens’ engagement with the sector. This revised edition covers more topics and has more pages compared to the 2nd Edition. In addition to the print version, an electronic version is also available on our website.

While some of us in Prayas (Energy Group) have written the chapters, this Primer is the result of a collective effort involving all our members as well as reviewers and well-wishers. We would especially like to thank Dr Rammanohar Reddy, Dr Ranjit Deshmukh, Jatin Sarode, Gayatri Gadag, Daljit Singh and Ann Josey for review comments. We thank the post graduate students from TISS - Mumbai for feedback on the 2nd Edition. Our thanks also to Neeta Deshpande for improving the language and communication. In producing the Primer, we worked with three artists - Manjiri More, Sandeep Deshpande and Gayatri Jog. We thank them for their patience and creative support. We would also like to thank Mudra for the layout and printing. A very special thanks to Shilpa Kelkar and Manabika Mandal from our group who worked tirelessly on production and data. This Primer would not have been possible without them. A special thanks also to everyone at Prayas (Energy Group) for their many contributions to the Primer at different stages of production.

In this age of internet and abundance of information, there could be questions on the usefulness of a Primer. Our view is that the Primer helps the citizens to gain an understanding of the basic concepts and broad issues in the sector. This is essential to decide what information to search, where to search and how to search. We hope that citizens will employ this Primer to educate themselves about the electricity sector and meaningfully engage with it by raising focussed questions and providing suggestions.

Prayas was founded 25 years ago. While we reflect on our long journey of public interest oriented policy and governance engagement, we are happy to bring out this completely revised edition of the Primer. We look forward to your feedback.

Prayas (Energy Group)

January 2019

Foreword to the 2nd Edition

Electricity is the prime mover of a modem economy. Not only is it a basic infrastructure, but it has also become an essential part of our daily existence, in the first hundred years of its commercialization, electricity was supplied to consumers by vertically integrated monopolies. It was generally felt that this was the only feasible option due to its complexity as a commodity and its natural monopoly aspects. In many countries worldwide, unbundling of the electricity supply industry was started during 1990s, so that it could be subjected to market discipline rather than being controlled through monopoly regulation. It was around this time that India embarked on the path of reform and restructuring of the sector, the enabling legal framework of which has now been enshrined in the Electricity Act 2003. The Act, which is landmark legislation, aims at development of a power system which catalyses investment, promotes competition and protects consumer interest.

Prayas - a dedicated non-governmental organization with focus on energy, health, learning and parenthood and resources and livelihoods - has been working for quite some time towards improvement of India’s power scenario. The Energy Group of Prayas has contributed significantly in capability building through publications and analyses of important issues facing the sector, and also through workshops and discussions.

Originality of approach is the unique feature of the activities of Prayas. The book, “Know Your Power: A Citizens’ Primer on the Electricity Sector”, bears testimony to this fact. This book exhaustively covers the technical, operational, economic and financial aspects as well as the reform models envisaged in the power sector. It explains each of these issues in a very simple and lucid manner. The book examines with precision the basic concept of the power system, and goes on to describe how the system works. It deals systematically with the economics of electricity, including cost structure and the tariff setting process. The publication also presents, in an unbiased manner, an overview of emerging trends. The book caters to the requirements of ordinary citizens as well as technical experts, by providing a comprehensive overview.

The 1st Edition of the book received overwhelming response from readers cutting across various interest groups, and proved to be a major capacity building tool for individuals and institutions.

I am glad that Prayas has now brought out this 2nd Edition, with finer refinement and updation, based on discussions and feedback from the readers. It is a very handy reference manual for every stakeholder interested in India’s power sector and seeking to contribute to its development. I am sure that this excellent publication would continue to serve as a useful primer for civil society and power sector professionals, and prepare them for an informed debate on the complex issues concerning the electricity sector.

Ashok Basu
Chairperson,
Central Electricity Regulatory Commission
May 2006

Preface to the 2nd Edition

The 1st Edition of the Primer was sold out in about a year’s time. Considering the limited effort that we could put into distributing the book, this is indeed a sign of citizens’ eagerness to ‘know their power’. The Primer has reached a varied audience - politicians, bureaucrats, farmer organisations, trade unions, consumer groups, teachers, students, environmental activists and many interested citizens. Institutions which have purchased the Primer include Ministry of Power, Regulatory Commissions, Electric Utilities, Training Institutes, Research Libraries and Funding Agencies.

From our readers, we have received many compliments as well as comments. This feedback has been a great help in bringing out this edition. Our own learnings and the recent changes in the power sector have also influenced us while preparing this 2nd Edition. Data has been updated upto 2005 and major events in 2006 have been taken into account, for example the issuance of the National Tariff Policy. We have added more illustrative examples to present concepts more clearly. Most of the Chapters have some changes and Chapter 9 (The Indian Power Sector: Emerging Trends) has been completely rewritten. Errors have been corrected and the Reference and Index sections updated.

Pushkar Wagle helped with editing two chapters and Daljit Singh helped with the review of the 2nd Edition. Nikit Abhyankar, Ravi Kadam, Abhay Dhamdhere, Pradnya Phagare, Prasanna Wagle and Gorakh Phale from our office have been with us during all stages of production of this edition. Their help was invaluable and we thank all of them. Special thanks to Shri. A.K. Basu (Chairman CERC) for writing a Foreword to this edition.

Some of the readers have pointed out that this book is not a Primer, but rather a handbook. We feel that the book is indeed a Primer if read from cover to cover. However, for understanding a specific area or issue, it could function as a handbook.

We hope this 2nd Edition empowers many more interested citizens and we welcome your feedback.

Prayas (Energy Group)

July 2006

Preface to the 1st Edition

The power or electricity sector is a key infrastructure sector and is the backbone of the Indian economy. The installed power generation capacity in India has grown 77 times since independence. There are around 11 crore electricity consumers in the country and the total revenue of all electricity distribution utilities in the year 2001-02 was nearly Rs 93,000 crore. The total revenue receipt in the Government of India budget of the year 2001-02 was just about twice this -
Rs 2,03,000 crore. Rural electrification and spread of irrigation pump-sets have increased the agricultural productivity. With electricity reaching nearly 85% of the villages, industrial activity (small and big) has become more widespread. With electrification of nearly 56% of rural households, the quality of life has improved significantly for those who have access to electricity.

Until the 1980s, the Indian power sector was in the growth phase with many achievements to its credit. But, by the late 1980s, almost all the State Electricity Boards (SEBs) started showing signs of financial, technical and governance failures. The 1990s started with the state supported entry of private companies into generation. The sector reforms commenced in the mid-1990s and many SEBs were restructured with financial support from international financial institutions.

Today, after more than ten years of power sector reforms, we do not have any great successes to boast of. The sector is still financially and technically sick. Moreover, in the ‘reform’ phase, we had disasters like Enron and admitted failures like Orissa’s attempt at reform, staring us in the face. Questions are being raised about the appropriateness of strategies and policies, but it is said that there is no going back on reforms. Today, governments are working out new strategies, governance models and tariff policies. The state supported SEBs are giving way to a mix of public and private corporations. The Electricity Act 2003 and the associated policy changes are expected to correct some of the previous shortcomings.

This state of flux has thrown up many new issues. There have been major changes at the policy level. There are many new players in the sector. Steps have been initiated to reduce the role of the State. The role of market forces has started increasing. Using the window of the Regulatory Commissions, public debate on policy issues has increased.

Policies in this sector should address the concerns of the vast majority of the poor while protecting long-term ecological interests. It is also clear that India cannot afford to copy the high consumption based models of the power sector in the developed countries. The appropriate model and policies of the Indian power sector should be scripted by the people themselves. But, unfortunately, we find that local expertise is not sufficiently involved in the policy process. In order to understand and comment on the reform process, we need to reach out to more people and build skills in technical, economic and legal fields. There is a need to enhance the influence of informed analytical actors in the Indian power sector. Such a collective effort alone can produce a balanced critique of the reform process and exert a healthy pressure on the policy process. This book forms a part of our efforts for building capabilities of common citizens to meet such an objective.

This book covers the basic technical and economic concepts of the power sector. Electricity in the energy context is introduced and components of the power system and their co-ordinated operation are explained. A quick tour of the day-to-day operational centres of the power system gives an overview of how these systems work. Players in the Indian power sector and their roles are briefly covered.

The power sector is quite complex in terms of operations and planning. We have attempted to explain the basic economic concepts, tariff issues, power system planning and the recent trends in the Indian power sector. We have also tried to explain the necessary jargon in a simple nontechnical language, using analogies and diagrams. This includes IPP tariff calculation, T&D loss estimation, Demand Side Management, Generation planning, Pumped storage systems, etc. After reading this, we hope that a citizen would be less mystified about the sector, and would have crossed the first hurdle towards a better understanding of the sector.

This book has emerged from the experiences of Prayas (Energy Group), Pune. Prayas has worked with many citizens’ groups in India and abroad on power sector issues. This includes consumer interest groups, industry associations, power sector employee associations, farmers’ organisations, power sector professionals, political analysts, energy analysts, journalists, policy makers and academics. This book addresses one of the major training needs expressed by many in India and similar developing countries. We realise that there is lack of material that comprehensively covers the techno-economic aspects of the power sector. This book is expected to fill this gap.

With a broad range of concepts to cover, writing this book has been a challenging experience. Our audience is a mixed lot in terms of background and expectations. If we keep the level of coverage too basic, we run the risk of irritating the knowledgeable. If the level is too complex, then we may distance the vast majority including those with good knowledge in some selected areas of the sector.

We have therefore kept to the middle ground. Certain items requiring complex explanations, equations or high level of detail are given in boxes or endnotes.

We must acknowledge that this primer is an output of a collective effort spanning the past two years. Many friends from consumer groups, the academic world and utilities have helped us. Those who helped at the early stages of conceptualisation include
Prof. Amulya Kumar N Reddy, Dr. Krishna Prasad and Dr. Vivek Monteiro. We have benefited from the inputs received from Dr. Uma Rao, Dr. NDR Sarma,
Dr. D.V. Ramana, Dr. M. P. Parameswaran, Dr. M. V. Ramana, Dr. Jhumur Lahiri, Danesh Gojer, K. Raghu and many friends from power utilities. Pallavi Apte and Ramesh Dhanokar have prepared the illustrations.
Dr. Usha Raman and Ms. Sherna Gandhy have helped with the editing. Abhay Dhamdhere, Pradnya Phagare, Prasanna Wagle and Gorakh Phale from our office have been with us during all stages of production.

It is our hope that this book will be both useful and engaging. We welcome readers’ comments and suggestions to improve it further.

Prayas (Energy Group)

May 2004

1 : The need for a primer on the electricity sector

In this book, we introduce and explain the technical and economic fundamentals of the Indian electricity sector. The sector is considered complex and technical by many. We wish to demystify the sector, explain the jargon, and help the reader to understand the issues involved. Our aim is not so much to create expertise, but to develop a perspective of the different important aspects of the electricity sector, which will help citizens to engage with it. We will be happy if we succeed in enabling the reader to ask the right questions about the sector. We also suggest some alternative approaches to address the challenges facing the sector, but not a blueprint for change.

The night bus to the city had been running along deserted roads for several hours. A speck of light gradually appeared on the distant horizon. As the bus approached the city, bright electric lights of diverse hues, shapes and sizes came into full view - visible signs of urban prosperity and the many comforts of our times. Asked to name a single invention that changed the quality of our lives, many would single out electricity.

Since its invention, electricity has captured our imagination and brought about many fundamental transformations in our lives. Electricity has become the bedrock of modern life. It lights up homes, streets and offices; powers mobile phones, televisions and appliances; and runs motors in factories and on farms. Industrial production, communication facilities, health care, education, transport and agriculture have all benefited from electricity. Today electricity is a key input to economic growth which in turn improves the quality of life. However, while it is one of the most versatile forms of energy, electricity is far from benign. Its production, transmission and use have impacts on the environment and livelihoods.

All of us are somehow connected to electricity, either as consumers or as people affected by the production or use of electricity. Though we may deal with the electricity sector to resolve our complaints as consumers, it is equally important to engage with the sector as citizens.

Everyone should have access to quality electricity supply that is affordable and supplied in the cleanest way possible. Sustained engagement of citizens with the electricity sector can work towards this goal and protect long-term human and environmental interests. Such an engagement requires an understanding of the electricity sector and its linkages with the economy, development, natural resources and the environment.

This primer is an effort to help the reader to develop a comprehensive understanding of the electricity sector. The introductory chapter explains the linkages between development, energy and electricity. Further, we explore why electricity is special as a form of energy, and discuss the flux in the electricity sector since the onset of liberalisation in 1991. We conclude with our objectives for writing this book, with the hope that it enables citizen contributions towards shaping the electricity sector.

1.1 The linkages between development, energy and electricity

Development can be defined in very many ways. Rather than explaining what we mean by development, it is perhaps easier to point out what development is not: it is not limited to economic growth and an increase in the supply of goods and services, nor should it mean unlimited consumption by a few. Development takes on different meanings in a variety of different contexts. It requires a balanced combination of economic growth and equity in distribution across all people, species and generations, causing minimum damage to the environment and livelihoods. An important requirement of the development process is that energy policies and institutions are planned and operated with inputs from all, especially the marginalised¹. It is the people who should decide the nature, content and process of development. Development efforts should ensure that the basic energy needs of the entire population are met, while paying special attention to marginalised communities and discouraging luxury consumption.

In simple terms, energy is the ability to do work. It exists in many forms like chemical energy, heat, light, motion and electricity. It cannot be created or destroyed, but can be converted from one form to another. Energy supply and end use play important roles in the development process. The history of civilisations has been fundamentally shaped by their sources of energy, its supply and use. Ancient societies primarily relied on traditional biomass and animal power. The industrial revolution in Europe was fuelled by coal. Petroleum began to dominate in the 19th century, and its availability in a few countries is a major source of global conflicts to this day.

But today, resource depletion and the challenges of climate change are restricting the use of fossil fuels. Renewable energy sources like solar and wind power will be increasingly used in the coming years. In the long run, it is also likely that centralised supply options will be replaced by distributed energy generation. There is also an effort, though considerably weak, to reduce consumption - not only of energy, but of all natural resources.

Energy supply and use have a strong correlation to development. There is no single indicator to measure development, but what comes closest is the Human Development Index (HDI), which is a combination of per-capita income, life expectancy and the level of education. The HDI for different countries is plotted against their per-capita energy consumption in Figure 1.1.

Figure 1.1: Correlation between per-capita energy consumption and HDI

Source: HDI data from Human Development Report of UNDP, available at http://hdr.undp.org/en/data and per-capita energy consumption data from IEA key world statistics 2018, available at: https://webstore.iea.org/key-world-energy-statistics-2018.

We can see from the figure that there is a high correlation between HDI and energy consumption. For countries like India which are located at the elbow of the curve, a slight increase in energy consumption could imply a big change in HDI. It is interesting to note that some countries like Sri Lanka and Philippines with lower per-capita energy consumption than India have higher HDI. It should also be said here that we should not aim for the very high levels of energy consumption of the developed countries since it may not be sustainable. Another point to note is that increasing energy supply with the expectation of achieving a desired HDI of 0.8 (considered a good level of development) by all countries at the current modes of energy production would require depletion of natural resources at nearly double the rate at which they can be replenished. What is desirable is a more equitable distribution of the use of energy - across countries in the world, and within countries, across regions and people. It is also necessary to improve end-use efficiency and change the modes of energy production so that its impact on natural resources and ecology is reduced.

1.1.1 Development deficit and energy poverty in India

India has been witness to many changes since independence. A vast and diverse country, it is difficult to classify India into any one category to describe it, not to speak of developing solutions that would work for everyone, everywhere, all the time.

Independent India began its journey as a rural nation - only 17% of Indians lived in urban areas in 1951. Agriculture was the mainstay of the economy, generating 56% of the GDP in 1951. Some 70 years after, India today is a rapidly urbanising country with its economy driven by services and industry. A third of our population now lives in urban areas, and agriculture, while continuing to employ nearly half of the population, accounts for only 17% of the GDP.

India has also emerged as a land of tragic contrasts, where pockets of ostentatious luxury and comfort co-exist with abject poverty and deprivation. Inequity in the distribution of income has been on the rise. Thus, while one in every five Indians is considered ‘very poor’ (earning less than US$ 2/day), India is also home to the fourth highest number of dollar billionaires in the world. In a country which put a satellite into orbit around Mars, most households still cook using wood on smoky chulhas which are extremely harmful to health. Several smart city projects and failing rural infrastructure exist side by side. We have huge malls, fancy airports, world class hospitals and schools of international standards, yet the state of public transport, health care and education is dismal. Please see Box 1.1 The thousand lens - have a look to understand India better.

Figure 1.2: Large number of people depend on non-commercial sources of energy such as smoky chulhas

Photo credit: photo by Karan Singh Rathore on http://flickr.com at https://www.flickr.com/photos/44221799@N08/6768398713

Box 1.1: The thousand lens - have a look to understand India better

Let us imagine that we Indians are reduced to a representative sample of 1000 and live in a small community. In this India, 485 are women and the rest are men, while 690 live in the villages. 270 are illiterate and 200 do not have enough to eat. About half the houses have mud floors, and less than half have drinking water in their premises. Around 650 have a toilet in their premises.

More than half the workers are involved in agriculture and less than one-tenth in the IT sector. There might not even be one doctor in this community (there is one doctor for 1500 people in the country). There are 1170 mobile phones, about 470 televisions and 100 computers. There are also around 450 bicycles, 210 two-wheelers and 50 cars. With the LPG mission, it is reported that 800 now have LPG connections, but still may be using firewood also to cook. As of mid - 2018, 950 have electricity connections in their homes. The richest 100 earn half of all the income in the country, whereas the bottom 500 earn about one-sixth.

1.1.2 Energy supply and use

In India, the major source of energy is coal which generates about half of the total energy supply. Coal is closely followed by biomass, largely used for cooking, and then oil, primarily used for transport, with a small but growing contribution of renewables. Figure 1.3 shows the breakup of energy sources for 2015. This pie-chart includes biomass, considered a non-commercial energy source, and all other commercial energy sources.

Figure 1.3: Energy supply - commercial and non-commercial in 2015

Source: Compiled by the authors from India energy balance data by International Energy Agency (https://www.iea.org/countries/India) and India energy dashboard (http://indiaenergy.gov.in/edm/)

The distribution of energy use in 2015 is provided in Figure 1.4. Industry is the largest user of energy, followed by residential consumers. Nearly three-fourths of the residential energy use is for cooking (using biomass). Please see Box 1.2 The 1000 lens: Have a look to understand the energy use better.

Figure 1.4: Energy use in 2015

Source: Compiled by the authors from India energy balance data by International Energy Agency (https://www.iea.org/countries/India) and India energy dashboard (http://indiaenergy.gov.in/edm/)

Million Tonnes of Oil Equivalent (MTOE) is a unit used to compare different forms of energy. As per IEA data, of the total 844 MTOE of energy supply in India (in 2015), 331 MTOE (nearly 40% of the total and 70% of the coal energy) is used for generating electricity. From 331 MTOE of energy used to generate electricity, after the different types of conversion losses, 85 MTOE of electricity is available for end use. Coal, biomass and petroleum products are the other energy sources for end use. The contribution of electricity as a source for end use has been growing and is now about 15-20%. With the growth in rural electrification, further industrialisation, appliance use, railway electrification and electric vehicles, the contribution of electricity is likely to increase.

Box 1.2: The 1000 lens: Have a look to understand the energy use better

In the middle of the Indian commune of a 1000 people, is an ‘Energy Tree’ with 1000 fruits. Everyone collects fruits from this energy tree. There are two types of fruits - processed (representing commercial energy sources including coal, oil, and electricity) and unprocessed (representing non-commercial energy sources including firewood and dung). On the Indian energy tree, there are about 340 unprocessed fruits, which are picked by two-thirds of the community for cooking. The remaining 660 consist of 310 oil & gas fruits, 200 coal fruits and 150 electricity fruits, which are plucked by different people. Out of these 660, industry picks up 310, transport picks up 65, homes and offices pick up 90, agriculture picks up 25 and others pick up 170.

As we saw in Box 1.1, nearly 950 in the community pick up 150 of the electricity fruits from the energy tree. According to current plans, in a few years, everyone will have access to these fruits and there may be enough of these fruits for all to pick up. In any case, everyone uses the products manufactured and services provided by those who pick up the electricity fruit. Whether people have access to electricity in their homes or not, they do walk under street lights, use pumped water for their fields, visit hospitals or use medicines, and travel by electric trains.

Figure 1.5: The energy tree

Source: Prayas (Energy Group)

Our story is about the electricity fruit: how it is produced and sold, who produces it, who sells it, and who buys it. Also, who looks after the tree.

1.1.3 Electricity and development

Electricity is one of the main forms of energy, amounting to around 20% of total energy use. It is widely recognised that electricity can be instrumental in promoting education, providing health care, reducing drudgery, improving sanitation, and encouraging income-generating opportunities. While electricity is not a sufficient condition, it is a crucial input to catalyse development. Figure 1.6 represents the two-way relationship between electricity and development.

Figure 1.6: Two-way relationship between electricity and development

Source: Prayas (Energy Group)

Development is brought about by several factors including an equitable increase in income, better education, improvement of health, and enhanced community enablers. Some of these relate to the individual, others to the family, and yet others to the community. These factors are not mutually exclusive, and each consists of diverse components, as listed in Figure 1.6.

In the last decade, India has made significant progress in providing electricity connections to houses. After setting up connections, providing quality and affordable access to electricity can enable and catalyse improvement in all areas which contribute to development. Improving education and health outcomes and increasing income earning capabilities aid human capital formation, and ensure that the local economy can employ people productively. Access to electricity also ensures improved living conditions, and access to a better quality of life. Thus, providing electricity for all is not only equitable and just, but also necessary to catalyse economic and social development. Any efforts towards this objective should therefore be perceived as a social and economic investment, rather than a social obligation. It is also important to acknowledge the two-way nature of this relationship. Development leads to an increase in the demand of electricity as well.

Many policy makers have understood the correlation between electricity and development as briefly described in Box 1.3 Policy action on electricity and development in different countries.

Box 1.3: Policy action on electricity and development in different countries

A historical cross-country survey over the past many decades illustrates the importance given to electricity by policy makers. For example:

In 1920, V Lenin, the architect of the Soviet Union, said that “Communism is Soviet power plus the electrification of the whole country”. He went on to add that “Only when the country has been electrified, and industry, agriculture and transport have been placed on the technical basis of modern large-scale industry, only then shall we be fully victorious”. Communism was considered to be the next stage after socialism and Lenin considered electricity to play a major role in this transition.

In the early 1930s, the government of the United States embarked on the New Deal, which constituted a series of federal programmes, public work projects and financial reforms in response to the Great Depression and aimed at the recovery of the economy. Rural electrification was a crucial component of the New Deal. The Rural Electrification Administration was set up, rural electricity cooperatives were formed, and cheap electricity was provided through federal generation projects. As a result, rural electrification increased massively from 10% in 1930 to 95% in 1955.

Ambedkar, the architect of the Indian constitution, also played a key role in the formulation of the legal and policy framework of the electricity sector in independent India. In the debates leading to the drafting of the Constitution, as well as the Electricity (Supply) Act (1948), he said: “… (what approach) will enable India to be equipped with electricity by treating it on the same basis as a strategic railway, that is to say, as an undertaking which must be started without consideration of immediate profit?… Why do we want cheap and abundant electricity in India? The answer is that without cheap and abundant electricity no effort for the industrialisation of India can succeed …Why is industrialisation necessary? … We want industrialisation in India as the surest means to rescue the people from the eternal cycle of poverty in which they are caught.” There was significant progress towards electrifying villages in the country after independence.

Access to electricity was seen as a key to the development of rural China, after independence in 1949. There was steady progress in rural electrification, supported by centralised grid and many community-owned small hydro power projects. Rural household access went up from 53% in 1978 to 97% in 1998. By 2010, China declared universal household access.

The first manifesto of the African National Congress in 1994 laid great emphasis on electricity. Electrification was mentioned as a major public works programme, part of the rural development programme to end rural poverty, and a component of the ‘housing and services for all’ initiative. Rural household electrification in South Africa increased from 10% in 1990 to 70% in 2010.

1.2 What is special about electricity?

Electricity - a key infrastructure sector - forms the backbone of the Indian economy. Like other infrastructure sectors, it requires large investments, and projects are implemented over long time frames. The sector has also been doubling in size every 10 to 15 years. Historically, on an average, 10-15% of the total five-year plan expenditure has been allocated to the power sector. The installed power generation capacity has grown 300 times since independence. There are over 25 crore consumer connections in the country (80% are domestic) and in 2015-16, the total revenue of all distribution companies was nearly Rs 4 lakh crores. (To place this in perspective, the tax receipt in the Union budget of 2015-16 was a little less than four times this amount, at Rs 15 lakh crores). Rural electrification and irrigation pump sets have increased agricultural productivity. Agriculture and domestic consumers get subsidised power as a matter of policy to increase access. This subsidy has been provided by the government either as a direct subsidy or a cross subsidy provided by some other classes of consumers (industry, commercial). With electricity reaching nearly all villages, industrial activity has become more widespread. Quality of life has improved significantly for those who have access to electricity. However, though it is true that electricity has reached all villages and most households, many rural and poor consumers only get intermittent power supply of poor quality.

The story of electricity goes a long way back to 600 BC in Turkey when Thales, a mathematician, rubbed a piece of amber on his coat to clean it. To his surprise, he found that the amber attracted pieces of wood! This is the first known observation of static electricity. Thales knew the story of Magnus, the shepherd of Crete, who had discovered loadstone, which attracted iron. It was much later, in 1600 AD, that William Gilbert - a British physician and physicist - termed the attractive property of amber as ‘electricity’, since amber is ‘elektron’ in Greek. For a long time, electricity remained an item of curiosity value. It was only three centuries later, after many experiments, inventions and engineering innovations, that electricity began to work for mankind. There were many people who played key roles in this journey. The American scientist Benjamin Franklin flew a kite during a thunderstorm and showed that lightning is electricity. The Italian scientist Alessandro Volta made the first electric battery. Michael Faraday, son of a blacksmith who become a professor at the Royal Institute in London, is known as the father of the electric motor and generator.² Thomas Edison, an American inventor, developed the first electric bulb and built a generator and distribution system in New York to supply electricity to 85 consumers. This was a Direct Current (DC) system. The Serbian-American engineer Nikola Tesla invented the transformer and along with the American entrepreneur and engineer George Westinghouse promoted Alternating Current (AC) systems. The production of the operational transistor in 1947 by a team from Bell Telephone Laboratories in the US speeded up the use of electronic appliances.

Figure 1.7 : What is the use of electricity: Faraday with new born child

Source: Prayas (Energy Group)

Electricity is one of the most versatile forms of commercial energy. It can be economically transported over long distances and can be easily converted to heat, light or motive power. For many specialised uses like electrolysis, powering communication systems or medical equipment, there is no option but electricity. It does work for us, but cannot be seen, heard, smelt or touched. It cannot be stored in large quantities and therefore has to be used as it is produced.³ It travels at the speed of light. Another special feature of electricity is the way it flows, obeying the laws of physics and not contract documents. At the point of use, it does not cause pollution. Electricity is becoming increasingly essential for many activities in everyday life, so that the demand for electricity is not very sensitive to its price for many consumers.

Though electricity is quite cost effective at the place of use, generating and transmitting it over long distances is complex and requires very high investments. It also significantly impacts the environment, natural resources and livelihoods. Due to inefficiencies in the generation and transmission of power to its place of use, a power utility has to generate nearly 1500 Watts of electricity to make 1000 Watts available to a rural household. To do this, it has to invest around Rs 1 lakh for generation and distribution, and to be economically viable it has to recover Rs 6 for every hour of use. These are only the economic costs of electricity. In addition, there are many hidden costs like pollution, submerged forests and villages, climate change, and impacts on livelihoods. These are not easy to quantify, but need to be considered while planning electricity generation and end use.⁴

1.3 The ongoing flux in the electricity sector

As we will see in later chapters, major changes have taken place in the Indian power sector from 1991 onwards with the onset of economic liberalisation. From being a state-owned monopoly with administrated prices, the power sector is transitioning towards increasing private ownership and market-based pricing. There has been significant growth in generation capacity, shortages have reduced, and progress achieved in rural electrification. There has been very fast growth of renewable energy (especially wind and solar), with falling prices and aggressive capacity additions. Many new players have entered the scene. Private companies own nearly half the generation capacity today.

The saga of the Enron corporation has been instructive about what not to do in the electricity sector. The distribution business was privatised in Odisha and Delhi, though this privatisation in Odisha was reversed in 2015. Distribution franchisees which manage the distribution for the distribution companies are operational in some urban areas. State Electricity Boards have been split into separate companies managing generation, transmission and distribution. Many international consultants, lending agencies and equipment manufacturers have come to India. Electricity regulatory commissions have been set up and they have started conducting public hearings. Distribution companies have accumulated high financial losses and three large national financial bailout schemes have been implemented in the last 15 years. People have been protesting against new power plants as well as transmission lines. Finally, consumer organisations and other civil society institutions have increased their role in policy and regulatory engagements.

1.4 Why this primer?

The Indian electricity sector today faces multiple challenges: low quality of supply to rural and small consumers, deteriorating health of distribution companies, the limitation of natural resources like coal which form the mainstay of electricity production, and the climate and ecological impact of electricity production and distribution. The first step towards addressing these challenges is to understand the electricity sector, which is the rationale for this book.

In terms of its role and potential, the electricity sector is of key importance to India’s economy. The healthy development of the sector requires informed and analytical thinking with a long-term public interest focus. This should include promoting the interests of the small consumers (agriculture, small business and small households) and the environment.

This book has emerged from the techno-economic primer sessions held in Prayas workshops, which have created a lot of interest and initiated many discussions over the past two decades. Over the years, Prayas has prepared various guides and booklets to familiarise the reader with the electricity sector. This book covers the techno-economic aspects of the sector in depth, and fills an important gap in the literature through a comprehensive treatment.

Chapters 2 and 3 introduce the technical concepts and functional components of the power sector. Chapter 4 takes the reader on a conducted tour of the sector to understand how things work. Chapter 5 provides an overview of the main players in the sector. Chapters 6 and 7 cover the economic and tariff aspects. Power system planning is a crucial subject, which is addressed in Chapter 8. Chapter 9 covers the major changes in the sector following the reforms introduced in early 1990s. Chapter 10 outlines the emerging trends and challenges in the sector following the increasing penetration of renewables and markets. Actors should decide the drama they wish to play, but we have supplied an outline of the plot for the drama in Chapter 11, ‘Know your Power’. We have used boxes and chapter endnotes throughout the book to highlight issues, answer frequently asked questions, and clarify difficult concepts. List of reading material has been included for those interested in further study. We hope you enjoy the book and find much food for thought and action!

Endnotes

¹ Marginalised groups may be identified based on factors like caste, income, location (urban, rural or remote tribal), religion or gender. These groups are not mutually exclusive or homogenous in terms of the causes of marginalisation, its extent, and ways of exiting the marginalised status.

² After Faraday demonstrated the effects of electricity and magnetism in one of his lectures, he was asked, “These all look very fascinating, but what is the use of this electricity?” He is said to have replied, “There are some who may look at a new born baby and ask, what is the use of this child? Your question is just like that!”

³ Though large-scale, battery-based storage of electricity has been reported recently, it will take some time for it to be widely commercialised.

⁴ Since there are additional social and environmental costs involved in the generation and distribution of electricity, it is not fair to say that those with paying power can use any amount of electricity they wish to. Thus people may be paying the economic price for the use of air conditioners or water heaters or other luxuries, but someone else pays the social and environmental costs. Indiscriminate use of non-renewable natural resources like coal or oil is not fair to future generations nor the environment.

2 : Understanding the Technical Concepts

How does the electricity generated thousands of kilometres away reach our homes? Can we check our electricity bill based on the appliances and hours of use? Why do some consumers face low voltage? Why is three phase supply common? In this Chapter, we explain the basic technical concepts of electricity to find answers to such doubts. This includes DC and AC systems, understanding reactive power and power factor. Using school level physics, we explain concepts like power flows in an AC circuit and three phase systems. Brief description of the components of the electricity or power system, based on technical, commercial or management functions, is given. Equations and units commonly used in the sector are introduced.

We have become so used to the idea of electricity that it is perhaps difficult to imagine a world without it. But for most of human history, there was no electricity. While experiments on electricity were conducted over centuries, the widespread use of electricity is really a 20th century phenomenon.

We all use electricity to charge our mobile phone batteries, but how does this electricity generated thousands of kilometres away reach us? In fact, why does lightning that strikes a far off place affect our power supply? For that matter, why should an erratic monsoon result in power shortage, or a worker’s strike at a coal mine lead to increased power cuts? How can excess power generated in Odisha be used to relieve power shortages in Kerala? We know that we are billed for the number of ‘units’ of electricity consumed, but what is a unit?

To explore such questions, we need to first understand electricity and the power system. This chapter will explain the basic concepts of electricity and help us understand how it reaches our homes.

2.1 Electricity: The basic concepts

Let us begin with understanding some basic concepts about electricity. We start with the electric circuit and work our way up to the more complex concepts of current, the difference between AC and DC, and the power factor.

2.1.1 The electric circuit

All of us are familiar with the simple hand torch, powered by a battery, where the bulb glows when the switch is turned on. Let us look at the electric circuit in Figure 2.1, which represents this simple arrangement. ‘Circuit’ is a technical term used to describe the inter-connection of wires and devices. In this electric circuit, there is a battery with two terminals - one positive and one negative. One wire connects the positive terminal to the switch, which has two states - ON and OFF. From the switch, another wire is connected to the bulb, and a third wire connects the bulb to the negative terminal of the battery. The bulb glows instantaneously when the switch is put ON, and turns off when the switch is put OFF.

Figure 2.1: A simple circuit

The battery is a storehouse of chemical energy. When the switch is put on, the chemical energy is converted into electrical energy, which flows through the wire, and through the bulb, generating light. If the bulb is switched on for a long time, the stored energy in the battery will be used up till there is no energy left in the battery, when the bulb will turn dim and ultimately turn off (For a quick science lesson on flow of electric charges, see Box 2.1 Atoms and electrons).

Box 2.1: Atoms and electrons

All matter is made up of tiny particles called atoms. Every atom consists of a dense nucleus and electrons which orbit around the nucleus. The nucleus is composed of protons and neutrons. While the electrons have a negative electric charge, the protons have a positive electric charge, and the neutrons have no electric charge (See Figure 2.2 for a simple representation of an atom.) Electrons are attracted to the protons in the nucleus by electromagnetic force. Usually the number of electrons and protons are the same, and the atom has a neutral (zero) electric charge. If the atom loses electrons it becomes positively charged, and if it gains electrons it becomes negatively charged. The unit of charge is a coulomb (C), and 1 coulomb is equal to the charge on about 6 million million million electrons (that is 6 followed by 18 zeros!).

Figure 2.2: Model of an atom

Electrons can get detached from their atoms and move around. You can imagine them floating in the gaps between atoms or finding another atom to stick to, which may result in another electron being expelled from that atom. Atoms of some materials can lose electrons more easily. Such materials also allow electrons to pass through them more easily. Such materials are called conductors (for example: most metals like gold, copper, aluminium). Some materials do not allow electrons to pass through them easily and are called insulators (for example: glass, wood, plastic).

Now let us use wires of copper, which is a metal and a good conductor of electricity, to make all the connections in Figure 2.1. When the switch is put ON, electrons flow from the negative terminal of the battery, through the wire and the bulb, to the positive terminal. One can imagine that electrons are ready to flow as soon as the switch is put ON. This is somewhat similar to how water is ready to flow as soon as the tap is opened, or how a sprinter is ready to run as soon as the whistle is blown. It is as though there is some pressure on electrons to flow away from the negative terminal towards the positive terminal. When electrons flow through the bulb, it glows. If the switch is kept in the ON position, electrons will flow from the negative terminal to the positive terminal until the chemical energy stored in the battery is exhausted.

This flow of electrons is ‘electric current’ or electricity. Current is measured in Amperes (A). 1 Ampere is equal to 6 million million million (6 followed by 18 zeros) electrons flowing through the circuit every second. Thus, we have a relationship between coulombs and amperes, where 1 Coulomb of charge flowing per second gives 1 Ampere of current. While this is a simple explanation, it is not strictly correct to say that current is due to the flow of electrons. The actual speed of electron flow through copper (called drift speed) is very slow, of the order of 0.3 mm/second, but the bulb glows instantaneously when the switch is put ON. This is because electric energy travels much faster, nearly at the speed of light, and explaining this phenomenon is beyond the scope of this primer. In some ways it is similar to how water flows out of a pipe the moment it is opened, though it takes a longer time for a drop of water from an overhead tank to flow to the tap.

Conventional current direction

We can see here that electrons flow from the negative terminal to the positive terminal. However, the conventional current direction is from positive to negative. This is because the conventional direction was defined before electrons were discovered and has been retained in present day nomenclature. Scientists then believed that positive charge flowed through the wires. This is however not ‘wrong’ since in some cases the flow of electricity can be due to the flow of positively charged particles (ions) as well. For this reason and for consistency, the conventional direction is still the norm, that is current flows from the positive to the negative terminal.

In order to explain electrical concepts, let us compare the working of this circuit with that of another system involving water flows.

The water circuit analogy

Consider a water tank with a tap and a wheel below it, as shown in Figure 2.3. Imagine that water in the tank is always maintained at the same level. There is a tap at the bottom of the tank that opens to allow water to flow down. There is a wheel between the tap and the ground. If water is allowed to flow through the tap, the water will fall on the wheel which will cause the wheel to turn. When the tap is closed, there is water pressure at the tap because of the water column in the tank. It can also be seen that there is some distance between the tap opening and the wheel. The energy with which the water hits the wheel is equal to the ‘potential energy’ of water, which is dependent on the difference in height between the water level in the tank and the wheel.

Now, we open the tap and let the water flow out, as shown in Figure 2.4. The water falls on the wheel, which will turn as long as the water keeps flowing. From the wheel, the water will splash down to the ground, as shown in Figure 2.4. We can say that the water falling on the wheel makes the wheel turn because, as we just discussed, there is energy in the water that hits the wheel. If the tank is located higher, the water will be dropping from a greater height onto the wheel, and thus with even more force, making the wheel turn faster.

Figure 2.3: Water tank with tap closed

Source: Prayas (Energy Group)

If water in the tank is not replenished, the level will keep dropping so that the flow will reduce, making the wheel turn more slowly. When the water in the tank runs out, water will stop flowing out of the pipe and hence, the wheel will no longer turn.

Figure 2.4: Water tank with the tap open

Source: Prayas (Energy Group)

Though there are many differences in the examples of the electric circuit and water flow, the water circuit does help us understand some key concepts about the electric circuit. The wheel in the water circuit is analogous to the bulb in the electric circuit. The water tank and the ground can be seen as the terminals of the battery in the electric circuit, while the tap is like the electric switch. The flow of water is analogous to the flow of current in the wire.

Pressure at the water tap, which in turn is caused due to the height of the water in the tank, is necessary for water to flow. Similarly, in the electric circuit, the difference in potential energy is necessary for electric current to flow. The measure of the difference in potential energy in the electric circuit is called the ‘potential difference’ or ‘Voltage’. Just as the difference in the heights of the water level in the tank and the wheel is a measure of the force of the flowing water as it falls on the wheel, the voltage is a measure of the energy of the electrons leaving the battery as they flow in the circuit.

2.1.2 Voltage, Current and Resistance

We now know that current is the flow of electrons, and that for electrons to flow through the circuit there needs to be a potential difference (voltage) across the circuit. Voltage provides energy to the electrons, and as they move through the circuit the electrons transfer some energy to the bulb which then glows. Copper is a good conductor and electrical wires are often made of copper. If you connect a bulb through a copper wire to the battery, then current will flow easily through it. However, if you were to connect that bulb through an iron wire to the same battery, the current flow will be less (your bulb will glow less brightly). Why should this be the case? Simply because iron has more resistance than copper, and thus for the same voltage, less current will flow through the wire.

Mathematically, this relationship between voltage, current and resistance can be written as:

Voltage = Current × Resistance

We know that current is measured in Amperes (A), and it can be measured using an ammeter. Voltage is measured in Volts (V) using a voltmeter, and resistance is measured in Ohms (Ω) using an ohmmeter.

⇒ 1 Volt = 1 Ampere × 1 Ohm

This is the famous Ohm’s Law and states that voltage is equal to the product of current and resistance. What does the Ohm’s law say? It says that 1V is needed to make a current of 1A flow through a wire of resistance 1Ω. If the resistance is 2Ω, then 2V would be required to make the same 1 A of current flow.

Resistance - like friction - is an inherent property of all materials to oppose the flow of electrons through them. Resistance causes loss of energy in the form of heat. Conductors like copper and aluminium have low resistance, while insulators like wood and plastic have high resistance. In fact, the resistance in certain materials causes them to significantly heat up or light up when electricity passes through them. Hence, the bulb’s filament is made of material like tungsten that heats up and emits light as electricity passes through it. An increase in the length of the conductor will cause its resistance to increase, while an increase in the thickness of the conductor will cause its resistance to decrease.¹ Also, rise in temperature increases the resistance of materials.

2.1.3 Power and energy

In our circuit, the battery gives energy to the electrons; they flow through the circuit to the bulb, and in the bulb some of their energy is transformed into heat and light energy. The amount of energy consumed by the bulb per second depends on the ‘power’ of the bulb. Power is the rate at which energy is transformed or converted from one form to another. It is measured in Watts (W) and is related to Voltage and Current by the following equation:

Power = Voltage × Current

⇒ 1 Watt (W)= 1 Volt × 1 Ampere

Energy or work is measured in Joules and 1 Watt is the power required to do 1 Joule of work in a second. Electrical energy is dependent on the power and time of use. It is measured in kilo Watt hour (kWh or also commonly called Units). When a 1000 W (1 kW) appliance is operated for one hour, 1 kWh or I Unit of electrical energy is consumed. You can calculate electrical energy in kWh by multiplying the power (in kW) of the appliance by the hours of its use. In your home or in your place of work, the appliances (be it bulbs, fans, TVs or refrigerators) would have name plates or labels that state the normal voltage of operation in Volts and the power rating in Watts. See Box 2.2 on how to read a name plate.

Figure 2.5: Immersion water heater and LED lamp

Photo credit: Prayas (Energy Group)

Photo credit: photo by Suyash Dwivedi on https://commons.wikimedia.org/wiki/File:1500W_Immersion_Rod_(15).jpg

Box 2.2: How to read a name plate?

All appliances have a label or name plate, which gives details like the name of the manufacturer, model number, voltage, frequency and power rating. Figure 2.5 shows an immersion water heater and an LED lamp. On the name plate of the heater, one can see information like 230 V, AC 50 Hz, 1000 W. This means that the heater works on normal household supply and consumes 1000 Joule during every second of use. On the LED lamp, one can see 240 V, 50/60 Hz and 10 W. To know the power rating of a refrigerator, one has to look for the name plate on its compressor. The name plate of a mobile phone battery will display details like voltage, and capacity given in milli Ampere hour (mAh). If the capacity is 2000 mAh, the battery is capable of delivering 2000 mA for 1 hour, or 1000 mA for 2 hours, and so on.

The power ratings of some common domestic appliances are provided in Annexure 3.1 of the next chapter. Table 2.1 gives the summary of these units along with the comparable units from the water circuit.

Table 2.1: Understanding the simpler units of measurement

Now, we know that when electricity flows through a bulb, it emits both heat and light. Many other kinds of devices also heat up when they work on electricity supply. For example, a motor or computer heats up when used for long hours. This is because of the resistance of the materials in the device. Our earlier equation can be rewritten in terms of resistance as follows:

Power = Voltage × Current

Power = Current × Current × Resistance

= Current2 × Resistance

Thus, power varies in proportion to the square of the current. This relationship is very important. In our electric circuit given in Figure 2.1, the wire and the bulb have resistance. Both of them will receive power from the battery. Power consumed by the bulb will be:

Power (consumed by bulb) = Current2 × Bulb Resistance

Power consumed by the wire will be:

Power (consumed by wire) = Current2 × Wire Resistance

Let us take a copper wire which is 1-foot-long in our circuit. This wire has a resistance of 0.01Ω. If the current through it is 10A, then the power used by the wire is 1W. Not all energy delivered to us via the battery is useful. We also lose some energy during the transfer of energy from the battery to the bulb through the wire! It is obvious that this loss should be made as low as possible. We will discuss how this is done in the next section.

2.1.4 AC and DC

What is AC (Alternating Current) and DC (Direct Current)? Why are homes and offices wired for AC (i.e. wall sockets and outlets have AC current)? Why do some electronics, like our cell phones and computers, run on DC, but fans, lights and motors run on AC?

Both AC and DC are types of electric current and differ in the way their flow changes with time. In DC, the current always flows only in one direction - from the positive terminal to the negative terminal as shown in Figure 2.1. If we were to graph the voltage (or the current) in a DC system for a small battery (1.5V), the graph would be a straight line. In an AC system, the current flow would keep changing direction (alternating) periodically. The variation of voltage is similar to that of current. The voltages in DC (straight red line) and AC (varying blue line) systems are shown in Figure 2.6.

Figure 2.6: Direct Current and Alternating Current

Historically, developments in electricity were in the area of DC systems. Batteries were the first source of electricity and their chemical reactions provided, as they do till today, DC electricity. Even the first generator based on electromagnetic principles (the Faraday Disk) produced DC current. All the uses of electricity initially were based on DC current. Hence, it is no surprise that when the first electromagnetic AC generator was made, they added a ‘commutator’ to turn its AC current into DC current. The dominance of DC power remained unchallenged till the 1890s (See Box 2.3).

Box 2.3: Battle of the currents

The first commercial generating station in the US and its associated transmission network, set up by Thomas Edison, worked on DC systems. However, at the time, DC systems had very low voltage and transmission over long distances posed a problem. Edison had proposed small generating stations which would provide small communities with access to electricity, with power plants within a distance of 1 - 2 kms from the end user. This would have resulted in way too many generating stations, making it a costly proposition. This was because big generating stations were more cost effective, due to the economy of scale.

Some other entrepreneurs had started looking into AC systems instead. In 1888, George Westinghouse purchased Nikola Tesla’s patents for AC motors and transmission. Transformers provided a useful way of stepping up the AC voltage to very high levels and then back down again to usable levels. At higher voltages, the same power could be transmitted over longer distances at much lower current, which meant less power lost due to resistance in the wires or lines.

With Edison backing DC and Westinghouse backing AC, a very public battle ensued between the two, known popularly as the ‘battle of the currents’. Eventually, AC with its ability to be supplied over long distances from large generating stations triumphed.

What are the advantages of AC? It is easy to transform AC voltages using transformers. AC motors need less maintenance, and are also more robust and cost effective compared to DC motors. From 1891, AC current became the dominant option for generation, transmission and distribution in public power systems. DC motors continued to be used in applications which needed speed control or high starting power (like cranes or railway traction). It is another matter that the tide is turning again now, with long distance High Voltage DC transmission systems, new types of DC motors (called Brushless DC motors) as well as all DC homes powered by solar panels.

A simple AC generator

In 1831, Michael Faraday discovered the connection between magnetism and electricity. He found that when a magnet is moved near a coil (which is nothing but a long conductor wound into a circular shape), voltage is generated in it. He further found that voltage is generated in a coil kept in an area where the magnetic field is changing. This voltage is proportional to the rate at which the magnetic field is changing.

Figure 2.7: AC generator

Source: Prayas (Energy Group)

A very simple AC generator is shown in Figure 2.7. Two magnets are placed with the north pole of one facing the south pole of the other. The magnetic field is from the North to the South Pole. An electric coil is rotated in a clockwise direction in the gap between the magnets. The ends of the coil are connected to two rings. Brushes are connected to these rings to carry electricity to a bulb.

The rotation of the coil generates voltage and hence current in the coil, which is different at different positions of the coil, as shown in Figure 2.8. The angle (measured from a vertical reference line in clockwise direction) is 0 degrees when the coil is vertical, 90 degrees when it is horizontal after one quarter of a rotation, 180 when it is vertical again, and 270 when it is horizontal again. Voltage and current are high when the long sides of the coil are moving perpendicular to the magnetic north-south line, that is, when the angle is 90 degrees or 270 degrees. There is no voltage when the coil is moving parallel to the north-south line (0, 180 degrees).²

Voltage is in one direction (above the horizontal line, called positive) half the time, from angle 0 to 180. Then for the remaining half, the voltage is in the opposite direction (below the horizontal line, called negative). This can be called a cycle and this cycle repeats as the coil rotates. If the coil turns faster, the voltage keeps changing faster. For a given speed of rotation, the horizontal axis can be marked in time.

Figure 2.8: Voltage produced in the coil at different positions of the rotation

The current in the coil keeps changing based on this voltage - the higher the voltage, the higher is the current, and vice versa. As mentioned, this current is called Alternating Current. The number of times the cycle repeats in a second is called Frequency. Thus, frequency depends on the speed of rotation and is measured in Hertz or Hz.

Voltage and Frequency

The frequency of AC in India is 50 cycles or 50 Hz (which means that the AC voltage pattern in India changes 50 times in one second). Voltage and frequency are read together to understand the system of electricity supply in countries. Hence, household electricity supply in India functions on an AC system at 240 V at 50 Hz. In Europe as well it functions at 240 V at 50 Hz, while in the US it functions at 120 V at 60 Hz (See Box 2.4).

Box 2.4: 50 Hz vs 60 Hz

Today, most of Asia, Europe, Africa, Oceania and South America operate at 50 Hz, while North America and the northern parts of South America (Brazil, Colombia, Peru, etc.) use 60 Hz. The use of different frequencies is due to historical reasons. In fact, many different frequencies existed in the first few years of electrification. For example, the city of London had 10 different frequencies in 1918. Southern California operated on 50 Hz and did not completely change the frequency to 60 Hz till 1948. Later such frequencies were standardised allowing electrical equipment to be traded and some power grids to be interconnected. However, Japan continues to use two different frequencies, with the western part using 60 Hz and the eastern part using 50 Hz. They have frequency converting substations which convert the frequency between the east and the west. Another interesting example of different frequencies is the Itaipu hydro-electric project on the border of Brazil and Paraguay. It is one of the largest hydro-electric projects in the world and can produce 14 GW of power. However, since Brazil and Paraguay operate on different frequencies, ten of Itaipu’s twenty generators generate at 50 Hz for Paraguay and the other ten generate at 60 Hz for Brazil.

Whatever might be the system frequency adopted by a country (also called that country’s ‘standard frequency’), the stable operation of the interconnected power system requires that the frequency be maintained within a band of tolerance around the standard frequency, as we will see in Chapter 4. In India, currently the frequency has to be maintained between 49.85 Hz to 50.05 Hz.

Transforming voltage

Why is it necessary to transform the voltage? From Section 2.1.3, we know the relationship between Power, Voltage and Current. It can be seen that for a fixed value of power, the current will be less if voltage is increased. For example, if 1000 Watts (W) of power was to be provided at a voltage of 20 Volts (V), the current in Amperes (A) will be:

On the other hand, if the voltage is 200 Volts, the current will be:

Thus, the increase in voltage causes a decrease in current for the same power.

What do we gain by decreasing the current? Since power loss in the lines in the form of heat is proportional to the square of the current, the power loss is reduced if the current is reduced. Hence, the higher the voltage level, the greater the reduction in power loss. Thus, if the resistance of our transmission line is 0.1 Ohm, then the loss of power with voltage at 20 Volts would be:

Power (consumed by wire) = Current2 × Resistance = 50 × 50 × 0.1 = 250 W

However, with the voltage increased to 200 Volts, the loss of power would be:

= 5 × 5 × 0.1 = 2.5 W

By comparing 250 W and 2.5 W, you can see that a ten times increase in voltage reduces power loss by a hundred times. In a huge power network, there are thousands of kilometres of wires or lines through which current flows. There is power loss in all these lines, so you can guess the enormous potential for loss reduction in such a system. It is easy to transform voltages in AC systems, and this is one of the most important reasons that AC came to be preferred over DC. Thus, with an AC system, power can be generated at a low voltage at the generating stations. Then it is transformed to a high voltage using a (step-up) transformer and transmitted over the distance to the consumer locations. Here, the voltage is lowered using a (step-down) transformer and distributed to consumers. This reduces power losses in the system. Low voltage levels at homes reduce electricity shock hazards and also reduce the cost of appliances. See Chapter 3 for more details on transformers and shock hazards.

The slow return of DC: HVDC and LVDC

Nearly all power systems today operate on AC, since AC for a long time enjoyed some distinct advantages over DC, which are: (a) AC power could be ‘transformed’ from one voltage to another, which was of great help transmitting power over long distances, (b) AC power is easier to generate, and (c) motors operating on AC were cheaper and easier to maintain. Appliances work usually on AC current, while electronics use DC current and need adapters (with ‘rectifiers’) that change the AC in the outlets to DC.

While most of the transmission lines are High Voltage Alternating Current (HVAC) lines, High Voltage Direct Current (HVDC) transmission lines have also been used to transmit electricity in bulk over very long distances. HVDC lines suffer lower losses as compared to Alternating Current lines over long distances, and are better suited for use as underwater power cables and for interchanges of power between grids of different frequencies (for example, in Japan). In addition, Ultra High Voltage Direct Current (UHVDC) lines, operating at a minimum of 800 kV, are also being developed. The world’s first 800 kV UHVDC transmission line from Xiangjiaba dam in Yunnan to Shanghai (both in China) was completed in 2010. This UHVDC line has a capacity of 6400 MW.³ See Chapter 3 for details on some HVDC links in India.

With the increasing penetration of solar photovoltaic generation, there is a plan to introduce Low Voltage DC (LVDC) distribution for homes or neighbourhood networks (called micro grids). This is possible since Solar PV generation is in DC. Electronic appliances work on DC, and lights, fans and refrigerators which work on DC have been developed. In India 48 VDC is being proposed as the standard voltage for LVDC.

2.2 Electricity: The complex concepts

In this section we look at the AC power system in detail. Many of us find it very difficult to make any sense of AC. Even those of us who have studied electrical engineering find AC mysterious and puzzling at times. How can voltage and current oscillate 50 times a second? How does power flow in an AC circuit? What is active power and reactive power? If you put these questions to an electrical engineer, she will immediately begin to write equations and draw graphs to explain them. She may end up explaining everything while you may still be left clueless. Explaining concepts of an AC power system with the minimum use of diagrams or equations is no simple task. We make an attempt in this section to tackle some of these concepts.

2.2.1 What does Alternating Current mean?

We have read that Alternating Current (AC) is current that changes direction with time, but what does this exactly mean? Let us consider our bulb again, and instead of a battery, attach it to an AC generator
(a small generator, which is enough to power the bulb). We know that the rotation of the coil and its position vis-à-vis the magnets changes the voltage. If we were to reduce the frequency from 50 cycles per second (50 Hz) to a much slower frequency, say 0.1 Hz, (i.e. it would take 10 seconds for one cycle), the bulb in our AC circuit will flash on and off repeatedly. This is because the AC current moves in one direction (forward) and then changes direction (backward), as can be seen from Figure 2.8. Usually, at 50 Hz, it does this so quickly that our eyes cannot see the bulb flicker on and off.⁴

2.2.2 How does electric power flow in an AC circuit?

Let us start with a relatively easier concept of power flow. How does current, which goes back and forth in a coil (in an AC circuit) do any work? How does it transfer energy? Let us understand this using an analogy. Let us say that you have a friend who loves to read books, but is not very good at organising her (many!) books. However, she has recently purchased a new book shelf. She has asked all her friends, including you, to help her arrange her books on the book shelf. All the friends form a line between the pile of books and the bookshelf, and pass the books from one to the other and finally to your friend who is next to the book shelf. Imagine that you are the person closest to the pile of books. You swing left to pick up a book from the pile and then swing right to pass it on to the person on your right, after which you swing back again to the left to pick up another book. The book you passed on is transferred in the same way and eventually reaches your friend who puts it on the book shelf. The swinging motion used to pass the book gets the book from the pile to the shelf, as shown in Figure 2.9.

Figure 2.9: Friends passing books

This example shows that material can move from one end to another even when the intermediate carriers do not move from end to end. Similarly, if a group of people are standing in a line, and the person at the end pushes the person in front, this ‘push’ can travel to the beginning of the line, making the first person jerk forward. Energy is transmitted in an AC circuit in a somewhat similar way.⁵ This energy, which is capable of doing work, is called ‘active’ energy, and its power is called ‘active power’. In a DC circuit there is only one kind of power, and that is active power. An AC circuit, however, has two kinds of power - active power and reactive power. We explore these concepts in the next sections.

2.2.3 Different kinds of power: active and reactive

In Section 2.1.3, we discussed the formula for power. This formula is for total power, which is the only kind of power in a DC system. For an AC system, however, this total power is composed of active power and reactive power, as shown in Figure 2.10.

Figure 2.10: Two kinds of power in an AC circuit

Active power flows from one end to the other end and does some useful work - like turning a fan or running a motor. Reactive power just goes back and forth between the source of power and the load (load is the technical term for the equipment connected to the circuit using power, see Box 2.5), but is necessary in an AC circuit.

We know from before that Power = Voltage x Current. For an AC system:

(Total) Power = Voltage × Current

⇒ 1 VoltAmpere (VA) = 1 Volt × 1 Ampere

In an AC system, the total power (also called ‘apparent power’) is measured in Volt Ampere (VA). AC system apparatus such as transformers, cables, etc. are rated in Volt Ampere. Part of this total power provides useful working power (active power), which is measured in Watts, while part of it provides phantom power (reactive power), which is measured in Volt-Ampere Reactive (VAR).

Reactive Power

Broadly speaking, reactive power is the power needed to create a magnetic field in AC motors, generators and transformers (called ‘inductive’ load, see Box 2.5), or an electric field in capacitors. Reactive power is also referred to as phantom or imaginary power since it does no work. But it helps to regulate voltage and is thus necessary for moving the active power through the lines in an AC power system.

To understand reactive power, let us consider pushing a ball along an inclined plane, from left to right, as shown in Figure 2.11. If we simply start pushing the ball in that direction, the ball will tend to move down the plane, from top to bottom. To prevent this, one of us will need to hold the ball up while the others would push it from left to right. The pushing from left to right is useful and is similar to active power. To keep the ball moving in that direction, we need to hold the ball up, which is like reactive power. Note that if the plane is not inclined, no reactive power would be needed. One can think of the inclined plane as an AC system, which requires reactive power, and a flat plane as a DC system, where no reactive power exists. Similar analogies to explain reactive power include kicking a football high so that it travels across the field (ball has to be kicked high for it to travel horizontally), constructing winding roads to climb up a hill (road has to go around the hill at a comfortable gradient to make climbing easier, making one travel longer horizontal distance, which is like reactive power) and a glass of beer having froth (reactive power) on top. Here is yet another analogy, which engineers may not approve. Think of your friends standing in a line, helping to stock your bookshelf. Now imagine that someone puts on some music. The music is like reactive power; it does not move the books, but it puts everyone in a more joyful mood as you and your friends go about the work.

Figure 2.11: Pushing a ball along an incline

Source: Prayas (Energy Group)

In Figure 2.8, we had drawn the voltage in the coil at different positions. If we were to draw the current in the same graph, it would follow a similar wave like pattern because, as we saw before, Voltage = Current x Resistance. While in a DC circuit, the current and voltage have similar pattern, it is rarely the case that voltage and current coincide in an AC system. We know that in the DC circuit, there is ‘resistance’ which opposes the flow of current. In an AC circuit, in addition to resistance there is also ‘reactance’ which opposes the current flow. Reactance is caused by inductors (which are present in motors) or capacitors. The net effect of resistance and reactance is called ‘impedance’. This impedance causes the voltage and current to not coincide (i.e. they are not ‘in phase’). When they are not in phase, there is reactive power in the system.

Box 2.5: What is ‘load’ and what are the types of load?

The power required by an electrical appliance connected to the grid to operate is called ‘load’. Since load is total power required, it is also made up of an active part (measured in Watts) and a reactive power part (measured in VARs). Load can be ‘resistive’, ‘inductive’ or ‘capacitive’.

Resistive load like that in ordinary bulbs and heaters does not need any reactive power to operate. Inductive load like that in motors and capacitors need reactive power. But there is a difference between the reactive power needed for inductive load and that needed for capacitive load. It is ideal if they cancel each other, as we will see later in this Chapter. If the grid has a high amount of inductive load (typically the case, since there are many motors), capacitive loads have to be installed to compensate for it, ideally as close to the inductive loads as possible. In simple terms, it can be said that capacitors generate reactive power to compensate for the absorption of reactive power by inductors.

As mentioned, inductive loads like motors require reactive power to maintain their magnetic fields. If they draw this reactive power from the system, it would require the electricity lines to carry reactive power to these inductive loads. However, transmitting reactive power from generating stations to motors requires more current to be carried by the lines, which results in low voltage and high losses. Instead, capacitors are installed at the locations of motors to provide reactive power locally to them. This minimises the amount of reactive power drawn from the system and allows for more actual power to be sent as a part of the total power.

2.2.4 Power Factor

Another concept to be understood is the power factor (pf). The power factor is the ratio of active power to total power in an AC circuit.

Thus, the power factor in an AC system is used to determine the active power and reactive power in the system.

Figure 2.12 shows the voltage and current in an AC circuit. At any point, the phase difference between the voltage and current waves is called the ‘phase angle’. Power factor is a measure of this phase angle (in fact, the power factor is equal to the cosine of the phase angle). Thus, the power factor measures the extent to which voltage and current are ‘out of step’. It has no units and is a number between 0 and 1.

If both the waves coincide, then the current and voltage are in phase and the phase angle = 0 degrees. In this case the pf = 1, as in the case of resistive load (like an incandescent bulb, water heating coil or electric iron).

If the current wave is behind the voltage one (i.e. the current ‘lags behind’ the voltage, as shown in Figure 2.12), then pf < 1 and lagging. In this case the load is said to be ‘inductive’, as in the case of motor loads, which are reactive and resistive. Thus, in our figure, the current lags behind the voltage such that the phase angle difference= 30 degrees, and then the pf = 0.5 (Cosine of 30). If the load is purely inductive, then the phase angle is 90 degrees and pf =0.⁶

If the current leads the voltage, then also pf is < 1 but leading. This happens when the load has a ‘capacitive’ component. If it is purely capacitive, phase angle is 90 degrees and leading, and pf = 0.

Figure 2.12: Voltage and current waves in an AC power system

Improving the power factor

Motors dominate electrical connections and have a power factor in the range of 0.7-0.8, which is to say that they are inductive loads and hence, have a lagging pf. To improve the pf, capacitors are connected to the motors. These capacitors provide reactive power and improve the pf (i.e. bring it closer to 1). Please see Box 2.6 for an example on the benefits of improving pf.

A high pf translates to efficient utilisation of power, which is important for consumers as well as the distribution company. Domestic consumers are charged based on actual power consumption (kWh or Units), since it is assumed that their consumption usually has a pf close to 1. Some high consumption inductive loads like water pump sets and air conditioners are mandated to be fitted with capacitors to improve the pf. Industries deploy many motors and their consumption usually has a low power factor. Distribution companies hence charge industrial consumers based on total power consumption (in VA) and may even have penalties for a low power factor. A low power factor results in higher currents being drawn by the load which increases line losses and reduces consumer voltage levels.

Box 2.6: Benefits of a good power factor

It is important to have a good (near 1) power factor. Many problems occur if capacitors are not connected at the motor to correct this pf to 1. Here is an illustrative numerical example:

Consider a 100 kVA distribution transformer in a village supplying power to agricultural pump sets. Let us assume that all pump sets in the village are of 5 hp (horsepower) rating and have a pf of 0.7. How many pump sets can be connected to the transformer and be supplied power from it?

Now, the total power multiplied by the power factor gives us the active power, which is measured in Watts.

Active Power = Total Power × pf

The active power supplied by the transformer is 70 kW, as shown below:

Active power = 100 × 0.7=70 kW

A 5 hp pump set consumes 3.73 kW of power. Thus, only 18 pump sets can be connected to the transformer. If more are connected, then the transformer will get overloaded. However, if appropriate capacitors are connected to all the motors, making the pf = 1, 26 pump sets (26 = 100/3.73) can be connected to the transformer without overloading it.

Being able to connect more pump sets to the same transformer is one benefit of a good power factor. There are other benefits - for the same number of motors, voltage improves and loss reduces. If all the 18 pump sets have a pf = 1, it can be seen that the transformer would be loaded only up to 67%, voltage at all pump set locations would be higher and the loss in the system would come down by half.

Please note that in DC systems, there is no reactive power and hence, total power = active power. Another way of thinking about this is that the pf = 1 in a DC system and hence, if we take the example in Box 2.6, the 100 kVA transformer will be able to support 100 kW of pump sets.

Active and reactive power flows in the grid

Now that we have some idea of active and reactive power, we conclude this section by explaining how to calculate the active and reactive power flows in the grid. This uses some high school level mathematics. Since grid is an interconnected network with many power generators, many loads and many lines connecting them (as will be explained later in Chapter 3), it is not easy to calculate the flows. But we take a simple example, where two points, say A and B, which are connected by a line in an AC system. Voltage at A is VA and voltage at B is VB. The line has resistance of R and reactance of X, but since usually in AC lines R is much smaller than X, for approximate calculations, we will neglect the impact of R. VA and VB may not be in phase and we assume that δ is the phase angle difference between these two voltages.⁷ In such a situation, active power flow PAB is given as:

PAB = (VA × VB × Sin δ)/X

If there is a generator at A and load at B, there will be a phase angle between the two voltages, making power flow from A to B. The higher the load, the bigger will be the phase angle and more power will flow on the line. If the line reactance X is reduced, then more power can be carried on the line.⁸ Higher voltage lines typically have lower reactance and therefore can transfer higher power.

Reactive power flow is given as:

QAB = (VA × (VB – VA) × Cos δ)/X

The reactive power flow will depend on the difference in voltage between the two points and the phase angle difference. A reactive load at B will lead to a voltage difference, making reactive power to flow from A to B. If there is no voltage difference, there will be no reactive power flow.

Thus, it can be seen that the active and reactive power flows in a grid depend on many factors - the power generation at different points, loads at different points, nature of inter-connection of lines and the reactance of lines. Some or all these parameters have to be changed to change power flow from one point to another, which is not an easy task. Power also flows nearly at the speed of light,⁹ making it difficult to manually manage the grid. We will discuss this further in Chapters 3 and 4.

2.2.5 Three phase system

In our homes, we can see cables from the distribution company entering our electricity main switch board: one live wire (carrying current) and one neutral wire. A third ground wire is usually connected from the board to the local earth pit in the building. The colour coding in a local wiring system is usually red for phase, black for neutral and green for earth. This is called a ‘Single Phase’ supply, and it is what is usually available in all small homes. Voltage between the phase and neutral is 240 Volts.

In big homes, buildings, offices or factories, there is ‘Three Phase’ supply. Three wires from the distribution company are connected to the switch board, and the fourth earth wire connects to the local earth pit. These three phases are usually distinguished by three colours - red, yellow and blue. A three phase system has three single phases combined. In a three phase system, the voltage between any of the two phases is 415 Volts, the standard Low Tension (LT) voltage in India. Voltage between any phase and the neutral is 240 Volts, the standard voltage for most household appliances. Figure 2.13 is a graph of three phase voltages - red, yellow and blue. It can be seen that three voltages have a phase difference of 120 degrees with each other.

Figure 2.13: Three phase system

What is the nature and need of a three phase system? Figure 2.14 shows a physical analogy of a single phase system.¹⁰ It has a special shaft (like a crank shaft) with a handle and attached to a piston, on both sides of a tube which is filled with some fluid. The left side shaft can be turned. Because of the special arrangement of the shaft, when it is turned, the left hand side piston on the top part of the tube moves back and forth. Movement of this piston pushes fluid to the right, making the right side piston move forward and backwards. Due to a similar arrangement, this causes the right side shaft to turn. The fluid flows back through the bottom part of the tube. This arrangement can make the rotary motion of the left shaft to be conveyed to the right shaft. This is similar to the power flow in a single phase AC system and the top tube can be considered ‘Line’ or ‘Phase’ and the bottom tube as ‘Neutral’. But the movement of the right shaft will be jerky, since the transfer of force is not uniform at different positions of the rotating left shaft. How can these two disadvantages - the need for a return path for fluid and jerky movements - be overcome? It can be done by modifying the arrangement using three tubes, each with a piston, as shown in Figure 2.15.

Figure 2.14: Single phase system analogy

In Figure 2.15, when the left side shaft is rotated, three left side pistons move in three respective tubes, causing the fluid inside them to push the right side piston. You can see that the positions of the three left side pistons are not aligned in one line, as also the right side ones. The special arrangement makes the right side shaft also to rotate. If fluid flows in all three tubes are the same, there is no need of a return path. The rotation of the right side shaft will be less jerky. Thus, the two disadvantages of a single phase system have been removed.

Figure 2.15: Three phase system analogy

Another analogy for a three phase system is a cycle with three pedals all connected to one elastic chain and gear. This cycle will have three seats for three passengers. If all of them pedal at the same speed, the cycle will go along smoothly. If one of them goes out of step, the chain will stretch a little, and there will be jerks indicating that all of them should fall into step.

Three phase systems have some advantages over single phase systems, the main one being that three phase power distribution is cheaper and three phase motors are more rugged and efficient.¹¹

But there is the obvious question, why three phases? Why not two, four, six or nine? It is not easy to answer this question, but one reason is that three is the minimum number for a balanced system. You would know this, having seen tripod stands or stools. More phases (like 6, 9 etc.) will also constitute balanced systems, but at a higher cost and complexity.

The active and reactive power in a three phase system depend on the phase to phase voltage (also called line to line voltage), current flow and the power factor.¹²

It is also necessary to understand the concept of balanced and unbalanced three phase systems. If (1) currents in all three phases are equal in magnitude and separated by 120 degrees and (2) the voltages from all the three phases to the neutral are also equal in magnitude and separated by 120 degrees, then the three phase system is called balanced. If not, it is an unbalanced system.¹³ An unbalanced system reduces the power output of motors, causes heating (of motors, transformers and lines) and reduces the power carrying capacity of lines. Therefore, efforts are made to ensure that this does not happen.

Some more units of measurement used in the power sector are given in Annexure 2.1.

2.3 Components of the power system

Now that we understand the fundamental concepts of electricity, we can now understand how the electricity system, or more correctly, the power system works. What is the power system? The network of generating stations, substations, power lines and loads is called the ‘power system’. The power system typically spans a large area. The power system can be divided differently depending on the function under study. In this section, we will look at the technical (physical), commercial and governance components of the power system.

2.3.1 Technical components of the power system

As soon as electricity is produced, it leaves the generating station, travels on the lines at the speed of light, and is consumed immediately. The moment a consumer puts a switch ON to start an appliance, something happens in a generating station somewhere.¹⁴

What is the process by which we get electricity? To understand this let us start with another question: what is the process by which you get a consumable good like soap? How are you able to buy soap from a shop near you? Soap is produced in a factory and then transported in bulk to dealers in various cities. It is then distributed to retail shops and bought by you to be used.

The power system network and operation can likewise be divided into the following four broad technical components:

Generation: This is the process by which electric power is produced or ‘generated’, i.e. the production stage. This can be done in different ways using different fuels.

Transmission: Electricity produced at the generating station is transmitted on lines to the place of use. Transmission is like bulk transport and operates at high voltages.

Distribution: Electricity is then distributed and supplied to consumers. Distribution is like the retail stage and operates at low voltages.

Utilisation or enduse: This is the process of using electricity for various purposes.

Unlike soap, however, electricity cannot be easily stored in large quantities, and once it is generated, it has to be matched by equivalent consumption. Supply has to equal demand or ‘load’ for the power system at each instant of time to function normally - which entails that the frequency is constant. This constant coordination is performed by system operation, as we will see in Chapter 4.

System operation: System operation coordinates the generation of electricity from stations with the demand in the system, and maintains a stable power system.

Figure 2.16: Schematic diagram of a power system

Source: Prayas (Energy Group)

Figure 2.16 provides a schematic of a power system. AC power is generated in power stations. Voltage is increased using (step-up) transformers so that this electricity can be transported over long distances on the transmission lines with low losses. These transmission lines form a network of electricity transmission and supply referred to as the transmission grid. Near the consumer location, the electricity is fed into distribution substations. Here the voltages are reduced using (step-down) transformers and the electricity is distributed to factories and homes on distribution lines on poles. This electricity is used for various purposes like lighting bulbs and running motors. With the introduction of distributed generation like roof top photo voltaic solar systems located at consumer locations, the situation gets more complex. This is covered in subsequent chapters.

2.3.2 Commercial components of the power system

An important point to understand about electricity here is that once it is generated and fed into the grid, all electricity is the same (unlike different brands of soaps). For example, there are no green electrons for green power, and if you are connected to the grid you will consume some electricity, but it is impossible to physically match that electricity to your supplier. The matching is done at the time of billing. Here we look at the various types of commercial transactions of electricity.

Wholesale markets: These are markets where bulk procurement of electricity is carried out. In India, big consumers having a minimum demand of 1 MW (like factories, shopping malls, housing colonies or distribution companies) can purchase power through wholesale markets. This can be through long term contracts or using the power exchanges.

Retailing of electricity: The sale of electricity to the final consumer (for ‘utilisation’) at a tariff is the retail sale of electricity. In India, the retail sale of electricity is combined with the distribution network operation, also undertaken by distribution companies. The retail supply of electricity involves purchasing power and then supplying it to the end consumers. After the sale, it involves reading the meters to determine consumption at each meter location (usually consumer premises), billing the sale and then collecting the amount of the bill from the consumer (this whole process is called metering, billing and collection). In India, distribution companies now undertake the physical distribution of electricity as well as the retailing.

Balancing and settlement: Even after planning and preparing contracts for generation and supply of power, the actual generation and consumption at an instant may differ from the plan due to many unforeseen reasons (imperfect demand forecasts, sudden outage of a generating station, etc.). These differences have to be kept track of and the system balanced (generation=demand, i.e. system frequency remains as close to 50 Hz as possible) and settled periodically. This function is done by system operators and market operators.

Trading in electricity: There are electricity traders who buy power from the generators and sell to consumers.

2.3.3 Management components of the power system

These refer to the process of setting up the legal framework, formulating the polices, undertaking the planning and regulating the power sector.

Law, Policy and Planning: The government plays the major role of preparing laws, policies and plans at national and state levels.

Regulation: Since the sector has many actors, regulation involves setting the rules and ensuring that they are followed. Functions of regulators include providing license to operate, approving major investments, deciding the performance standards, preparing regulations for the grid and market operations and setting tariffs. In India, generation is de-licensed, which means that anyone can build and operate a power plant, subject to a few conditions. Transmission and distribution are licensed activities, as is trading in electricity. Licenses for these are given by the electricity regulatory commissions. Regulations on safety are prepared by the Central Electricity Authority and Environmental Regulations by the Ministry of Environment, Forest and Climate Change.

Annexure 2.1 Counting Big, Counting Small

First let us get to know some terms to denote big numbers and small numbers. To understand them, it is convenient to understand the notation 10n, which is read as ’10 raised to n’ or ’10 to the power n’. Thus, 100 is equal to 102, that is 1 followed by 2 zeros. Similarly, small numbers can be written as a reciprocal of a big number. Thus, 0.01 is 1 divided by 100. In this case the notation is 10-n, which means 1/10n and is read as ‘10 raised to minus n’. Thus, big and small numbers are also given some names and abbreviations. Important ones are given in Table 2.2.

Table 2.2: Counting big, counting small

Horse Power

Watt was introduced as the unit of measure of power. 1000 Watts is equal to 1 kilowatt. An older and more popular unit of power is Horse Power (hp). Horse Power was introduced by James Watt in the 18th century, and as the name indicates, it had something to do with the power of horses. Watt thought of some real powerful horses and the power of such a horse was denoted as one Horse Power. 1 hp = 746 Watts. In reality, the average horse is only half as powerful as one hp!

Measuring energy

Joule, ‘Unit’ (kWh) and calorie are units of energy. Joule and Unit have already been mentioned before. Calorie is a unit used to measure heat energy and is equal to the heat energy needed to raise the temperature of 1 gram of water by 1 degree centigrade. Calorie and Joule are both units of energy and 1 calorie is equal to 4.2 Joules. A kilocalorie (kcal) is equal to 1000 calories. British thermal unit (Btu) is another commonly used unit of heat energy. It is the heat needed to raise the temperature of 1 pound of water by 1 degree Fahrenheit (1 Btu is incidentally equal to the heat emitted by a single matchstick!). 1 Btu is equal to 1055 joules. 1 million Btu is written as MBtu and sometimes MMBtu.

Calorific Value and Heat Rate

The calorific value (also called heating value) of a fuel is measured in kcal/kg. It is equal to the heat released when one kg of fuel is burnt. To illustrate, the calorific value of Indian coal varies from 2300 kcal/kg (lignite) to 5000 kcal/kg (hard coal). The calorific value of wood varies depending on the source and is in the range of 1500 (natural) - 3500 (dry) kcal/kg. LPG, petrol, naphtha, kerosene, diesel and fuel oil have heating value of 10,000 - 12,000 kcal/kg. For natural gas, it is measured in kcal/cubic metre and is about 10,000 kcal/cubic metre.

Heat rate is an important parameter for all thermal generation units, whether they are based on coal, gas or nuclear energy. To understand heat rate, it is necessary to understand the input and output of a thermal unit. Input is the heat produced by burning the fuel, and the rate of heat input is measured in kcal/hour (kcal/h). If we know the heating value and cost of the fuel, the input rate can be converted into Rs/hour as well. We will continue with kcal/h for now. The electrical power output of the generating unit is expressed in kW, which we know is a measure of electrical power. The input-output curve is a graph of the heat input rate in kcal/h against the power output in kW. Heat rate at any point on the curve is obtained by dividing the input by output.

Heat rate is measured in kcal/kWh. Its value can be different at different kW outputs. It can be seen that the heat rate is, in a way, the inverse of efficiency, which is typically given as output divided by input. Thus, the higher the SHR the worse the efficiency. In a generating station, there can be many generating units, each with a different heat rate. They are all averaged to calculate the Station Heat Rate (SHR).

MTCE and MTOE

When national level energy statistics are to be given and a comparison has to be made across different energy sources (say between coal, petroleum and electricity), units like Million Tonnes of Coal Equivalent (MTCE) and Million Tonnes of Oil Equivalent (MTOE) are useful. Coal and oil burn to give heat energy, but the amount of energy depends on the quality of the fuel. Using average calorific values of various fuels, the relationship between electrical energy (expressed in MU) and MTCE or MTOE can be written as:

1000 MU = 0.0833 MTOE = 0.17 MTCE

Consolidating units and abbreviations

Details on units of measurement as described in this chapter are given in Table 2.3.

Table 2.3: List of units of measurements

Endnotes

¹ Resistance of a wire is directly proportional to its length and inversely proportional to its cross sectional area. Hence thicker conductors are used to carry higher currents.

² The direction of flow of current in a wire moving in a magnetic field can be determined by using what is called the ‘Flemings left hand rule’. Extend the thumb, forefinger and middle finger of the right hand in mutually perpendicular directions. Your thumb should be in the direction of the motion of the wire, and forefinger in the direction of the magnetic field from the north to the south pole. The direction of the middle finger then shows the direction of current. The maximum current is produced when the maximum cross sectional area of the coil cuts across the magnetic field (see https://en.wikipedia.org/wiki/Fleming%27s_right-hand_rule, and search for AC generator animation videos, for example: https://www.youtube.com/watch?v=gQyamjPrw-U).

³ Please see: https://www.economist.com/blogs/graphicdetail/2017/01/daily-chart-14

⁴ This is due to the persistence of vision of the human eye, because of which an image is retained in the mind for around 1/10 to 1/15th of a second or 100 to 66 milliseconds. This is why you can see a circle by moving a sparkler around fast. A bulb working on 50 Hz AC power flickers around 100 times a second (goes off once every 10 milliseconds) and hence appears as a constant light to the human eye.

⁵ Here is a more complex explanation of the flow of energy in AC. Power is the product of voltage and current. In AC, both voltage and current change with time. If we multiply these using trigonometric equations, we get two components of power. Active power, which is always positive, pulsates at double the frequency and has an average value equal to V * I * Cos Ø, where Ø is the angle between V and I (this angle is called the phase angle). Since it has a non-zero average, it is capable of doing work. Reactive power also pulsates at double the frequency and is equal to V* I * Sin Ø, but has an average of zero. Hence it is not capable of doing any work. Reactive power flows are used to set up electric and magnetic fields in AC circuits. Since it pulsates at double the frequency, periodically, at double the frequency, it fully charges and discharges a magnetic or electric field (in a coil or a capacitor).

⁶ The X-axis of this graph is angle or time. Current lags voltage if it reaches maximum value later than voltage, and leads voltage if it reaches maximum earlier than voltage. One can also look at the sequence of zero crossings of current and voltage graphs. But one needs to differentiate the two zero crossings in a cycle - one where it crosses the zero and is increasing, another where it crosses zero and is decreasing.

⁷ Phase angle in a grid is a relative measure, just as height is measured above the sea level. Phase angle for any point is measured with reference to one pre-decided point in the grid - typically the substation with high generating capacity. Please note that this angle is between two voltages at different locations, and is not the angle between voltage and current at one location, which is a measure of the power factor, as explained before.

⁸ Maximum power transfer is possible when the phase angle difference (δ) is 90 degrees (since Sin 90 = 1). But usually, the phase angle difference between adjacent substations is limited to 30 degrees. A physical analogy to explain phase angle is two discs connected by a spring. One disc is rotated which makes the spring stretch a little (similar to the phase angle difference) and transfer the rotation to the second disc. If the first disc is turned with more force, the spring will stretch more, but beyond a point, the spring will break, making it impossible to transfer the rotation. It is not easy to measure the phase angle, but now there are Phasor Measurement Units (PMUs) which can accurately measure it.

⁹ We have seen the water circuit analogy for an electric circuit. In the water circuit, water flows out of a tap as soon as it is opened, since the pressure wave travels in water at the speed of sound in water. When current flows in a wire, it creates magnetic and electric fields around it in two mutually perpendicular directions. Mathematically, the electrical energy is the product of the electric and magnetic field strengths, and the flow of electrical energy is in a direction perpendicular to both fields, and thus along the wire. Thus, the electrical energy is not conveyed through the wire, but through the space around the wire, and this travels nearly at the speed of light.

¹⁰ Analogies for single phase and three phase system are adapted from the classic book, ‘Electric energy systems theory’, by OI Elgerd.

¹¹ There is another advantage of three phase over single phase, which needs some mathematics to explain. In single phase systems, the instantaneous active power pulsates at double the frequency. In three phase systems, the instantaneous power (the sum of power delivered by the three phases) is nearly constant. This can be seen by drawing graphs of single phase power and three phase power. Please see: https://www.electrical4u.com/advantages-of-three-phase-system-over-single-phase-system/

¹² Active Power = 1.732 × Total Power × Power Factor Reactive Power =1.732×Total Power × (√1-Power Factor ×Power Factor), where 1.732 is the square root of 3.

¹³ To calculate the percentage current unbalance, first measure all the three phase currents and calculate the average. Find the deviation of each of the three currents from the average. Percentage unbalance is the ratio of the maximum deviation to the average, expressed in percentage. A similar calculation can be done for voltage using phase or line to line voltages.

¹⁴ Adapted from the book, “Making competition work in electricity”, Sally Hunt, John Wiley, 2002.

3 : Production, distribution and end use of electricity

The technical components of the power system, namely, generation, transmission, distribution and end use have to work in close coordination to serve consumers. In this chapter, we introduce all these components. Generation based on coal, gas, nuclear, wind, solar, biomass and hydro sources are briefly described. Transmission system, which forms the interconnected grid and the distribution system which connects to the consumers are explained. End use or utilisation is described from the view points of the consumer and the electricity company.

In Chapter 2 we discussed important technical concepts related to electricity and introduced the technical functional components of the electricity sector, namely generation, transmission, distribution and utilisation. In this chapter we will explore these functional components in the Indian context. Take another look at Figure 2.16 showing a schematic of the power system. Electricity is produced at generating stations, transmitted over long distances by the transmission system, and reaches consumers through the distribution system. We now look at these systems in detail.

We begin with a discussion of electricity production, covering thermal, hydro and renewable generation. Next, we discuss bulk distribution (called transmission), followed by retail distribution (called distribution and supply). Following this, we cover electricity utilisation or end use from the points of view of the consumer and power utilities. The chapter ends with a brief overview of some relevant new developments.

3.1 Generation

‘Generating stations’ are the production centres of electricity. A generating station is made up of one or more generating units. A generating unit (except some like solar photovoltaic) has two basic components: a turbine, which produces rotary motion, and a generator, which converts this rotary energy to electrical energy. All other equipment that supports electricity generation is called ‘auxiliary equipment’ (and their electrical consumption is called ‘auxiliary consumption’). Rotary motion in the turbine is produced by different primary means: water or air pressure in hydro and wind turbines; steam pressure in coal, nuclear, biomass, solar thermal, or steam turbine in the combined cycle gas turbines; and pressure of hot gases in gas or diesel turbines. The solar photovoltaic generator is different. It has no moving parts and sunlight is directly converted into electricity using photovoltaic cells. Similar is the case with battery storage systems and fuel cells - they have no moving parts and convert chemical energy to electrical energy.¹

Today’s generating units are complex - consisting of the fuel handling system, turbine equipment, generator, pollution control system, substation to evacuate the electricity generated, and a control system to monitor the operation.

3.1.1 Components and functions of a generating station

Different fuels are handled differently. For hydro stations, water has to be directed to the turbine blades and then evacuated safely. For wind, the turbine blades have to be oriented so as to face the wind. For steam based plants, fuel (coal, nuclear or biomass) has to be transported to the station, converted to a suitable form (coal has to be crushed, nuclear fuel rods have to be prepared, etc) and used to heat water to generate steam at high pressure. Waste products after burning have to be disposed of. In the case of gas or diesel units, fuel has to be transported from a refinery and burnt and waste gases expelled. Solar panels that convert sunlight into electricity have to be fixed in such a way that they get maximum sunlight during the year.

The turbines of big stations are quite massive and complex. Hydro turbines rotate slowly, at about 70-500 revolutions per minute (rpm) and so do wind turbines at 5-20 rpm. Steam turbines rotate faster at 3000 rpm and gas turbines much faster at 12,000 rpm. The rotating turbine shaft is connected either directly to the generator or through a gear box to operate at an appropriate rotation speed. As we shall soon see, in AC systems, the frequency of the power generated is directly dependent on the speed of rotation of the generator shaft and the configuration of the magnets. Since frequency has to be maintained at 50 Hz, it is important to keep the rotation speed steady. It is also important to ensure that no part of the turbine gets overheated, and this is done by providing good lubrication and cooling.

Generators consist of a ‘rotor’, which is rotated by the turbine, and a stationary ‘stator’, which has a set of coils in which electricity is generated when the rotor rotates. We have seen in Section 2.1.4 of the previous chapter that if there is relative motion between the magnetic field and an electric coil, electricity is generated in the coil. The magnetic field is produced in the generator by passing current through the ‘field winding’ (also called excitation winding), which is on the rotor. Since the rotor rotates, so does the magnetic field. This rotating magnetic field induces electric current in the stator winding, which is the power output of the generator. The voltage of electricity generated depends on the current in the field winding, the power generated depends on the power with which the turbine turns the generator rotor, and the frequency depends on the speed of rotation. But since the speed of rotation is different for different kinds of turbines, how is the frequency maintained at 50 Hz? This is managed by having the appropriate number of magnetic poles in the generator.²

In addition to active power, generating stations are capable of supplying reactive power to the system. The amount of reactive power generated depends on the voltage of the field winding. With minimum consumption of active power, some hydro generators can be operated as what are called ‘synchronous capacitors’ to provide reactive power. In this mode, they behave like a variable capacitor. In solar photovoltaic plants, electricity generated is DC, which is converted to AC by inverters before connecting to the system. These inverters are also capable of supplying reactive power.

Coal and gas power stations release pollutants due to the burning of fuels. These mainly include carbon oxides, nitrogen oxides, sulphur oxides and coal ash. If the coal is washed in coal washeries, the ash content is reduced³ Electro-static precipitators at the station trap particles in the exhaust. Nuclear stations need to handle radioactive fuel and follow strict safety measures to ensure that there is no leakage of radiation. Storage of used (called spent) fuel (which is also radioactive) is another problem. All these stations also release significant amounts of heat, because less than half the heat generated through burning fuel is converted to electricity. Rest of the heat goes to water bodies into which water is discharged or the atmosphere.

Power is generated typically at 11-33 kV at the generating station. Since it has to be transmitted over long distances, the substation at the generating station steps up the voltage and connects the generating station to the transmission system. This substation may be connected to more than one substation to distribute power. This arrangement also ensures that options exist to get power supply from the grid for starting the station after a total power supply failure. Small wind and solar plants (kW scale) are connected to the grid at much lower voltages. For example, residential rooftop solar plants are connected to low tension supply at 415 Volts.

The monitoring and control system in a generating unit monitors the whole unit from a control room and helps to control various parameters like fuel supply, generation and voltage. The control room will also be in touch with the load dispatch centre for operation. Please see sections 3.2 and 4.2 for a description of load dispatch.

3.1.2 Understanding some terms

A generating station can have many generating units. They may have been built one after another over a period of time. Some key terms related to a generating unit are defined below. The same definitions are applicable in the context of a generating station as well. For example, the installed capacity of a station is the sum of the installed capacities of all the units in the station.

The ‘Installed Capacity’ of a generating unit is the maximum power (usually expressed in megawatts or million watts, written as MW) that it can generate. For many reasons, the maximum capacity may reduce a little over a period of time. The reasons for this can be reduction in water flow (in the case of hydro stations), reduction of equipment efficiency, partial failure of some components, etc. This reduced capacity is called the ‘De-rated Capacity’. The minimum generation level or technical minimum is the minimum MW at which the generating unit can operate in a stable way. For hydro units, the technical minimum is near zero, whereas it can be 40-70% of the installed capacity for coal based units⁴ For a station with many units, the minimum generation is the smallest value of the individual technical minimum of all units.

Energy generated by a generating unit is measured by metering instruments at the station. Energy is typically measured in Million Units (MU), and is usually calculated for a day or a month or a year. 1 unit is 1 kWh, and hence 1 MU is 1 GWh, which is the energy generated by a 1000 MW station running at full capacity for one hour. Energy can be directly metered or calculated if the average hourly MW generation is known. For a period of one year, that is 8760 hours (8784 hours for a leap year), energy generated is given as:

For example, a 100 MW generating unit working at full capacity will generate 2.4 MU in a day and 876 MU in a year. This calculation can be seen below:

‘Gross Generation’ is the total generation by the power plant and includes its ‘Auxiliary Consumption’, which is the energy consumed by the equipment needed to operate the plant. ‘Net Generation’ is the energy that is available after accounting for auxiliary consumption and is therefore available for further transmission to the consumers. It is called the generation available at the ‘bus bar’ of the generating plant.

‘Auxiliary Consumption’ is the energy consumed by the equipment which is required to operate the power plant. This includes fuel conveyers, pumps, pollution control equipment, lights, etc. It is usually expressed as a percentage of the energy generation of the unit. Table 3.1 at the end of this section gives the typical auxiliary consumption for different types of generating stations.

‘Average Capacity’ is a measure of the energy (MU) the unit generates over the year. It is usually calculated as the average of hourly MW generation over an entire year. It can also be calculated by dividing the annual energy generation by the number of hours in a year.⁵

The ‘Firm Capacity’ or power (or dependable or guaranteed capacity) of a unit is the power that can be assured from the unit at any point in time. Firm capacity is often relevant to hydro units (as well as wind units) and corresponds to the power generated during the minimum water (or wind) flow. ‘Secondary Power’ is the excess power available over firm power (say during monsoons). The concepts of firm capacity and firm energy are also applicable to consumer load that is assured to be supplied by the utility, transmission lines, etc.

‘Availability’ is a measure of the actual capacity available for generating power. For a generating unit, it is calculated as the average of the declared available generating capacity over a period of time (typically a year). It is expressed as a percentage of the maximum possible generating capacity, (which is the installed capacity minus auxiliary consumption). In a simple case where there is no partial reduction of generating capacity (reduction can happen due to the failure of some auxiliaries), and the generating unit is either ON or OFF, availability is the percentage of time the unit is available for generating power. It is given as:

In the case of hydro units, the quantum of hours for which the unit is ready for power generation in case water is available is considered.

‘Plant Load Factor (PLF)’ is a measure of the productivity of a generating unit. For a generating unit, PLF is calculated as the ratio between the gross actual energy generation to the energy it would have generated if it were operating at its rated capacity. It is given as a percentage and is usually calculated over a period of one year. Units which have high PLF are the base load units and those with low PLFs are the ones operated generally during peak load time.⁶

The ‘Capacity Utilisation Factor (CUF)’ is another measure of the productivity of generation, usually used for renewable energy generation plants like wind or solar. It is the ratio of the gross actual energy generated by the plant to the maximum possible energy that can be generated with the plant working at its full rated power capacity for all the time. Capacity utilisation factor is usually calculated over a period of one year and expressed in percentage. For solar plants, Wp (Watt peak, which is the solar power output under standard test conditions⁷) is used to calculate the maximum output. For wind plants, the rated capacity (given on the name plate of the turbine) is used. PLF and CUF are quite similar terms, but CUF is commonly used for renewable energy systems.

The next sections briefly describe different types of generating stations. We begin the discussion with coal based stations, since these are relatively more complex and make the highest contribution to electricity generation in India.

3.1.3 Coal based station

Figure 3.1 is a schematic of a coal based generating unit. Coal arrives in the form of big lumps transported from the mines mostly by rail, and over short distances by road or conveyor belt, while imported coal is transported by ship. Coal required typically for a few weeks of operation is stored in the coal yard. It has to be crushed to powder form and transported to the furnace where it is burnt. Fans blow air into the furnace to facilitate burning. Heated gas is used in the boiler to produce steam at high temperature and pressure. Dust particles produced during burning are to be filtered out using Electro Static Precipitators (ESP), sulphur oxides to be removed through Flue Gas Desulphurisation (FGD) systems,⁸ and nitrogen oxides through Selective Catalytic Reduction systems (SCR). The hot gases are released high into the atmosphere through a tall chimney. High pressure steam turns the steam turbine that turns the generator to produce power. The steam is cooled using cooling towers and the condensed water is reused by pumping it back into the boiler. Some water is lost in the process. Power is generated typically at 10-20 kV and the voltage is stepped up (raised) at the substation which links the generating station to the grid.

The amount of heat required for generating one unit of electricity, or the heat rate of a coal based station is about 2200-2500 kcal/kWh, which would require about 0.6-0.8 kg of coal/kWh depending on the calorific value of coal. There are many fans, blowers, pumps, and control equipment at a thermal station. These are called auxiliaries and they can consume up to 8-10% of the generated power. There are typically many generating units in a station. Each unit has its own turbine and generator but may share other facilities with other units in the station, including coal crusher, ESP, and chimney structure.

Figure 3.1: Coal based generating unit schematic

Source: Prayas (Energy Group)

There are two components which make up the cost of generation: the fixed cost which depends on the initial investment, and the variable cost which depends mainly on the cost of fuel. The fixed cost of a coal based station is less than that of a hydro station, but the variable cost and auxiliary consumption values are higher. A coal based unit takes a few hours to start up since it takes time to produce steam at high pressure. Cold start-up (after all components have been shut and cooled down) can take a few hours longer than warm or hot start-up. The generation level of these units is changed by controlling steam flow and pressure. Since there is a limit to the speed of change (due to thermal stress and related wear and tear), generation levels cannot be changed as fast as that of hydro or gas units. Coal based thermal stations are typically run as base load stations, generating at the same level most of the time. Since the number of components is greater and there are many moving parts, the maintenance requirement of these stations is more than that of hydro or renewable stations.

Indian coal has nearly 35-50% ash, whereas imported coal typically has only 5-10%. Ash disposal is a serious problem with coal based thermal stations. Big stations have ash ponds which span hundreds of acres since about 4-5 tonnes of ash/MW capacity is produced every day if Indian coal is used.⁹ All the fly ash produced is expected to be utilised (in cement, brick making, road laying, etc), but according to government reports only about 50-60% is being utilised.¹⁰ The overall efficiency of a coal station is about 25-40%.¹¹ Coal burning can also produce polluting gases like sulphur oxides, nitrogen oxides and fine particles. Techniques are available to minimise these emissions, reduce use of water, and limit release of fly ash. The Ministry of Environment, Forest and Climate Change regulates the mandating of these techniques, but implementation of such measures would add to the cost of generation.¹² The life of a coal plant is about 30-40 years.

3.1.4 Gas based station

Figure 3.2 gives a schematic of a combined cycle gas power plant. The fuel used can be natural gas (transported in ships as Liquefied Natural Gas or LNG, or as gas in pipelines), or naphtha (petroleum naphtha is a relatively cheaper liquid fuel, but is costlier than natural gas), which arrives at the generating station through pipelines from a refinery or port. For cost and safety reasons, very little fuel is stored at the station. Centralised storage supply to multiple stations benefits from the economy of scale. At the station, air is compressed and the fuel is burnt in a combustion chamber. This releases high pressure hot gases which drive the gas turbine. The exhaust gases escape into the atmosphere. The turbine turns the generator which produces power. The substation steps up this voltage and links the station to the grid. This is called the ‘open cycle gas turbine (OCGT)’ mode. It has a heat rate around 2700-3200 kcal/kWh and the efficiency is of the order of 30%.

Figure 3.2: Combined cycle gas power plant

Source: Prayas (Energy Group)

In ‘combined cycle gas turbines (CCGT)’, the exhaust gas from the gas turbine is sent back to the compressor, thus saving on heating. A Combined Cycle Gas Turbine has a gas turbine followed by a steam turbine. Output gases from the gas turbine flow into a steam generator: a heat recovery steam generator (HRSG). Steam produced here turns a steam turbine. This arrangement is more efficient than OCGT. In a gas based station, there will typically be a few open cycle units and one steam turbine. The heat rate is of the order of 1900-2100 kcal/kWh and efficiency is 45-50%.¹³

Gas stations can be constructed quite fast, and their pollution levels are quite low compared to coal stations. Auxiliary consumption in a gas based station is around 3-4%. Operation and maintenance of these stations is quite complex. Gas based stations can be started, stopped and the generation level changed quite quickly, compared to coal based stations. Thus gas based stations are a convenient choice to meet peak loads. The average life of a gas based station is about 30 years.

Diesel based stations are ideally suited to handle peak load conditions and emergency power requirements. Since the capacity of a diesel based station is usually low, it has a very low capital cost and requires very little space, but its fuel cost and O&M cost is high. It is also highly polluting. The typical life of such a station is five years.

3.1.5 Nuclear station

Nuclear stations are quite similar to coal stations. However, instead of burning coal, the process of nuclear fission produces heat, which in turn is used to produce steam that drives the steam turbine. Capital costs of nuclear stations are relatively high, and safety measures have to be stringent due to the radioactive nature of the wastes produced. Disposal of nuclear wastes poses special challenges that have not been fully resolved. Nuclear power was considered a very good generation option a few decades ago, since it was considered a ‘clean’ source as it has no emissions during power generation. In many countries including the US, France, and Russia, nuclear power forms a significant fraction of the total installed power capacity. Due to many unresolved issues like safety risks, waste disposal, decommissioning problems, fear of radioactive leaks as well as high costs, there has been a slowdown in the construction of nuclear power plants almost all over the world. Accidents at the Three Mile Island (USA, 1979), Chernobyl (USSR, 1986), and Fukushima (Japan, 2011) have contributed to this slow down. The US, for example, has not built a green field nuclear plant since 1977. France, which produces 76% of its electricity from nuclear,¹⁴ is debating its nuclear future. Germany is in the process of shutting down all nuclear reactors by 2022. Japan, which was generating 30% power from nuclear at the time of the Fukushima accident, had shut down all nuclear stations for safety checks. Some countries with plans of expanding nuclear power capacity include India, China, Russia, and South Korea.

Nuclear stations take 6-10 years to build, though some Indian stations have had time overruns of several years. They have an auxiliary consumption of 11-12%. They take one to two days to start up or shut down and are typically used as base load plants. The heat rate is around 2860 kcal/kWh and overall efficiency is about 30-35%. The typical life of a nuclear station is 30-40 years. De-commissioning a nuclear plant is a very complex and expensive task because of the radioactivity of fuels and wastes.

3.1.6 Wind turbine

Wind based generating plants can be set up in a few months and their operating cost is very small compared to fuel based conventional plants. They can be big MW scale systems which require a large area and investment, or small rooftop systems. Figure 3.3 is a schematic of a wind turbine.

Figure 3.3: Wind turbine schematic

Source: Prayas (Energy Group)

Large MW-scale wind based generation requires a minimum wind speed of 3-4 metre/second (10-15 kilometre/hour). This is called the cut-in speed. For safety reasons, it is not practical to operate at speeds higher than 25 metre/second (90 kilometre/hour). This speed is the cut-out speed. After a wind resource assessment (involving wind speed and direction measurement over at least a year), a wind duration curve is prepared. If the wind direction is not varying much and there are sufficient hours in a year when the wind speed is between the cut-in and the cut-out speeds, there is a potential for electricity generation using wind.

Wind turbines typically are 30-40% efficient (theoretical maximum efficiency is 59.3%) and at good speeds, can generate up to a few MW of power from one turbine. Power generated is proportional to the air density, cube of wind velocity, and the cross-sectional area.¹⁵ An approximate formula to calculate the wind power is given below.

Power = V3 × r2

where Power is in Watts, V is the wind velocity in metre/sec, and r is the length of one of the blades in metres.

Wind velocity increases with height (approximately in proportion to the 7th root of the height, that is height1/7) and is more stable at higher altitudes and at sea level. Hence the current trend is to build taller wind turbines with larger rotors (100-140 metres towers and 100-130 metres rotor diameters) and at offshore locations.

Typically, wind farms are planned with many wind turbines or generating units. Wind is a variable source of energy with diurnal and seasonal variation. The typical capacity utilisation factor is 20-40% but this is increasing rapidly with newer wind turbines.

3.1.7 Solar photo-voltaic and solar thermal systems

Solar radiation is used to generate electricity by direct conversion to electricity by solar photovoltaic (PV) systems, or conversion to heat by solar thermal systems. Solar radiation can also be used to heat water for cooking or industrial applications. This section looks at solar PV and solar thermal systems for generating electricity.

The incidence of solar energy on the earth varies with the time of day, the time of year, latitude of the place, shade, and cloud conditions. Solar radiation can have power as high as 1000-1300 Watt/square metre, and at current conversion efficiencies, a solar panel can produce 150-200 Watt/square metre. With all the additional fittings, a 1 kW panel will need 7-8 square metre or 100 square feet area.¹⁶ Such a panel will produce around 4-6 units per day. The efficiency of solar energy collection can be improved by tracking the sun, to keep the collector always pointing towards the sun.

Photovoltaic (PV) cells convert solar energy directly into electrical energy. The conversion efficiency is currently around 16-20% for crystalline silicon technologies and efforts are under way to improve it. The cost of solar PV power has drastically reduced over the past few years and is now about Rs 3.5-4 crores/MW (2018), which translates to a tariff of around Rs 3/Unit. Solar PV is very modular in scale and can be set up as large MW scale grid connected power plants or can also be set up in off-grid mode, in which case, battery storage is needed to ensure power during the night.

Figure 3.4 is a schematic of a grid connected rooftop PV system without storage. It shows the solar panels, an inverter which can be connected to the grid, and a two-way electricity meter.

Figure 3.4: Schematic of a rooftop PV system

Source: Prayas (Energy Group)

Box 3.1: How to set up a solar rooftop PV system?

Small kW scale rooftop photovoltaic systems can be set up in a few weeks especially if shadow-free roof space is available. The one-time cost of setting up a rooftop PV system is high, but the life time cost is quite low. The current Indian solar programme has a target of 40 GW for rooftop solar by 2022, whereas the actual installed capacity is of the order of 1.5-2 GW as on December, 2018. The government provides support in the form of capital subsidy for installation of small rooftop systems only for residential consumers, under the aegis of the Sustainable Rooftop Implementation for Solar Transfiguration of India (SRISTI) scheme announced in 2017. If you are a consumer planning to install a rooftop solar system, your best option today is to opt for a grid connected system. The next few paragraphs briefly describe the steps you need to take.

Estimate the size of the solar plant: The plant could be designed to generate nearly as much energy as you consume in a year. There are many mobile applications to help you size the plant. The approximate kWp capacity required can be calculated by the formula:¹⁷

The size of your solar plant can be equal to or less than your sanctioned connected load.

The typical cost of a plant consisting of solar panels, an inverter, a two-way meter and required wiring is around Rs 55-60/Wp. The Ministry of New and Renewable Energy (MNRE) periodically announces this benchmark cost. Small systems are eligible for a 30% subsidy. Around 100 square feet shadow free flat space, preferably south facing, is needed for a 1 kWp system. You can get quotations from local suppliers, who will also state specific procedures. MNRE, the state renewable agencies and many mobile applications also provide a list of local suppliers for ready use by interested parties.

Take permission from the local DISCOM: You need to take permission from the local DISCOM to set up this system. The permission is necessary since the solar power will flow into the distribution system when you do not need it (in the case of a grid connected solar PV). The local transformer needs to be capable of handling this power. Once the installation is complete, you need to approach the DISCOM to install the two-way meter in place of your current meter. This two-way meter will measure electricity flow from the DISCOM to you and vice versa.

Net-metering: Under net metering, electricity generated by the solar rooftop system is first utilised by the consumer for self-consumption. Excess electricity, if any, is exported to the grid. Net metering is a billing mechanism that gives credit for such excess solar energy exported to the grid. Consumer is billed only for their “net” energy use in a month.

You will be billed for your net consumption: Your periodic electricity bill will be determined by your net consumption, which is the difference between what you draw from the DISCOM and your solar generation. Since solar tariffs are lower than the average consumer tariffs, the payback time is around 3-4 years for residential consumers, and much lower for commercial or industrial consumers.

Such systems are ideal when power interruptions are very few, since there is no battery backup. This is also because when there is no DISCOM supply, you will not be able to use the solar generation for consumption. If you wish to have the benefit of such a feature, you need to invest in more sophisticated inverters coupled with battery storage.

In solar thermal systems, the sun’s heat is used to heat fluids like oil or liquid salt. Concentrators like parabolic mirrors help to focus all the light. With concentrators, temperatures can reach up to 800 degrees centigrade, which can be used to create steam to power a steam turbine, as in a coal based plant.

3.1.8 Biomass

Biomass, sourced from plants or animals, can be used to generate cooking fuel, electricity or compost for agriculture. Plant sources include forest or plantations, saw dust, seeds, agriculture residue, and marine organisms. Animal sources (covering humans and other animals) include municipal waste, industry waste, and excreta.

Biomass is converted to gas, fuel oil, or pellets/briquettes, which can be used for cooking, space heating or in a modified gas or diesel generator to produce electricity. The critical issue is the continued reliable and affordable availability of biomass. Co-generation¹⁸ in sugar mills is done using bagasse (a waste product of cane crushing) as an additional fuel. The cost of setting up such plants is around Rs 5.5-6.5 crore/MW while their cost of power is Rs 7-8.5/unit

Waste to energy plants have been planned in many cities using municipal solid waste. Capital subsidy is provided to set up such plants and the 2016 Tariff Policy mandates distribution companies (DISCOMs) to purchase all the power generated by them. But there are many challenges in the successful operation of such plants. Municipal waste is made up of different types of materials. Wet waste - consisting of vegetables, flowers, fruits, etc - constitutes the major portion by weight. Dry waste - consisting of combustible material like paper, cardboard and plastic - constitutes the second type of municipal waste. The third category of waste includes inert material like dust, metal, concrete, and drain silt. There is also toxic waste like pesticides, chemicals and radioactive material. These different types of waste need different kinds of treatment, which is possible only if they are segregated, ideally at source. Wet waste can be converted to compost to be used as manure, though this needs land space to store the waste during conversion to compost. It can also be used to produce biogas which can be used for power generation. Alternatively, after drying, it can be converted to pellets (also called Refuse Derived Fuel or RDF) which can also be used for power generation. Plastic wastes could be recycled though they have to be burnt at high temperatures, a process which can release toxic gases. Inert waste cannot be converted to energy and toxic waste has to be isolated. Indian waste is largely wet waste (by weight) and hence the ideal option is to segregate it at source and set up small plants (for composting or conversion to cooking fuel or electricity) in each locality. In fact, it is best to minimise the amount of waste leaving the premises.

Use of biomass for energy generation has not picked up as much as other renewable sources like wind or solar. The reasons include challenges in collection, segregation, and cost effective conversion to suitable energy sources.

3.1.9 Hydro station

Until 1980, hydro generation constituted 40% or more of the total installed capacity. Since then, the growth of capacity has been higher first for the coal plants; for a decade from 1990s for gas based plants; and from 2005 for renewable power. As of mid-2018, the hydro power generation capacity is around 45,000 MW, which is 13% of the total installed generation capacity in India (the corresponding world figure is 17%).¹⁹ According to government reports, the estimated potential capacity from hydro stations is about 145,000 MW. It is believed that hydro power generation does not cause any pollution and water is a ‘free’ renewable source of energy.²⁰ We will discuss this point in more detail later.

Hydro-electric stations can be micro (few kW capacity), small (less than 25 MW as per the Indian definition) or large (greater than 25 MW). Most of the discussion here is about large hydro. The life of a hydro-electric station is more than 50 years, compared to 30 years for thermal stations. The fuel cost is zero, but the initial capital investment for a hydro station is quite high (can be 1.5-2 times that of a coal based station). A hydro station can have many units, adding up to a capacity of 50-2000 MW. The station could be a multipurpose project with functions of power generation and canal based irrigation, or designed to fulfil only one of these functions.

Huge reservoir based projects (with big dams and long irrigation canal networks) often cause large-scale submergence of villages and forests. They can also have geological impacts (like earthquakes) and affect fisheries, since dams hamper the migratory excursions of fish.

Figure 3.5 shows a schematic of a hydro-electric power station. Water from the rainfall in the catchment area flows into the river through small streams and tributaries. The location of the dam is finalised based on considerations like the possibility of power generation, ease of construction, distance from nearest roads, power lines, geology, hydrology, flood forecasts, upstream and downstream projects and impacts, safety of the dam, and submergence of land, forests and people. Most hydro stations are located very far from load centres (cities of industry clusters). A reservoir is formed behind the dam and it can submerge thousands of acres of land. Penstocks are huge pipelines that carry the water from the reservoir to the turbine. A multi-purpose dam will have irrigation canals starting from the reservoir. Water is let out into these canals through gates, which can be raised or lowered to control the water flow.

Figure 3.5: Hydro station schematic

Source: Prayas (Energy Group)

The ‘Full Reservoir Level (FRL)’ is the maximum height of the water in the reservoir. FRL is typically reached at the peak of the rainy season. If water rises above FRL, it is let out through gates to protect the dam. The ‘Minimum Draw Down Level (MDDL)’ is the minimum level in the reservoir. If the water level falls below MDDL (during summers or earlier during drought years), power generation and irrigation will not be possible. Thus, plant operators strive to control power generation and irrigation canal flow, so as to keep the reservoir level between MDDL and FRL throughout the year.

Some hydro stations do not have a reservoir to store and regulate water flow. They are located right on the water stream (in a river or a canal) and are called ‘Run of the River’ hydro stations. These are typically small and are best suited to rivers which have assured water flow for most of the year.

There are some other hydro stations that have two reservoirs - one upstream (main reservoir behind the dam), and another downstream (tail race reservoir, after the dam). Such stations are called ‘Pumped Storage Stations (PSS)’. The generator and turbine of a PSS are located between its two reservoirs and are capable of acting like a motor and a pump. Thus, a PSS has two modes of operation - generating mode and pumping mode. In the generating mode, a PSS is like any other hydro station: water from the main reservoir is guided to the turbine making it rotate to generate power. Water leaves the turbine to accumulate in the tail race reservoir. In the pumping mode, water is pumped up from the tail race reservoir to the main reservoir. In this mode, it draws power from the grid. The overall efficiency of a PSS is about 70%. As of 2018, there are only 9 PSS stations in India and even they do not always operate in PSS mode due to many reasons.²¹

Water from the reservoir is carried to the turbine through penstocks. Near the turbine, there is an inlet valve that controls the water flow. Water pressure makes the turbine rotate. Hydro turbines turn at a speed of 70-500 rpm. After making the turbine turn, water leaves through the tail race. The tail race takes water back into the river downstream, or in the case of a pumped storage station, into the tail race reservoir. A rotating turbine drives a generator to produce electric power. The amount of power produced depends on the pressure and volume of water flow (See Box 3.2).

Box 3.2: Hydro generation: Types of turbines and calculation of power generated

The difference in levels of water at the storage reservoir and the turbine is called the ‘Head’. The Head is measured in metres and is like pressure. When water flows down through the penstock and valves, some pressure is lost due to friction. This friction head is around 5% and the remaining ‘net head’ contributes to power generation. The rate of flow of water is measured in cubic metres/second. One cubic metre is equal to 1000 litres.

Water flows from the reservoir through the penstocks to the turbine to generate power. The water at the bottom of the penstock is under pressure because of the height difference between the reservoir and turbine. At the turbine, if the water is converted into jets of water, then all the pressure energy will be converted into speed energy or kinetic energy. These jets turn the turbine producing rotational mechanical energy and such turbines are called impulse turbines. On the other hand, if the water is made to flow through an enclosed space in the turbine, making the turbine blades turn, the water will have high pressure energy and some speed energy. Both these types of energies are converted into rotational mechanical energy by the turbine. Such turbines are called pressure turbines.

Turbines have rotating blades mounted on an axis. There are three main types of turbines used for hydro power generation. The Pelton turbine was developed in 1889 and is like a water wheel. A jet of water hits the bucket-like turbine blades at a tangent, making the wheel turn. This is used when the head is very
high - 500 metres or higher. The Pelton turbine is an impulse turbine. The Francis turbine was developed in 1849. Water flows into the turbine along the blades in a radial direction and flows out along the axis. The Francis turbine is used when the head is medium, i.e. 15-500 metres. The Kaplan turbine was developed in 1913. The flow of water in a Kaplan turbine is like the airflow in a plane propeller. Water enters along the axis from one side and leaves from the other side, along the axis. These are used when the head is low or medium, i.e. 2-70 metres. The Francis and Kaplan turbines are pressure turbines.

Power generated by the turbine is related to the head, water flow rate and efficiency of the turbine. The higher the head or the water flow rate, the higher the power generation possible. Considering a turbine efficiency of 90% and generator efficiency of 85-90%, an approximate formula for electric power output by a hydro generator is:

where Power is in kW, Net Head in metres and Flow Rate in litres/second.

This formula is for active power. Like all generating units, hydro electric generators can also generate some reactive power. The amount of reactive power generated can be changed within some design limits. Some hydro-electric units can be run to generate only reactive power. In this mode of operation, called ‘condenser mode’, a minimum water flow is to be maintained and the unit will consume some active power from the grid (around 8-10% of its capacity). This is a special feature of some hydro units and is put to use to improve voltage in the system, especially during the non-monsoon periods.

From the operational viewpoint, a hydro station has some advantages over a thermal station. If water is available, a hydro station can be started up or switched off in a few minutes. It can also be easily operated over a wide range of power outputs with high efficiency to meet the requirements of the system. A hydro station needs very little electric power to generate power, that is, the auxiliary power consumption is very low, at about 2-3%. Since it has very few parts, a hydro station is simple to operate and maintain. With maximum efficiency of nearly 90% for the turbine and 85-90% efficiency for the generator, the overall efficiency of hydro power generation is very high, at around 80-85%. Due to all these factors, hydro stations are like a savings bank account from which money can be withdrawn or into which it can be deposited very easily. This flexibility in power output control is quite important for grid management.

But hydro projects are dependent on the availability of water to generate power and therefore can generate power only during some months of the year. Big hydro projects require big dams which throw up many controversial issues. See Box 3.3 on some controversial issues related to hydro projects.

Box 3.3: Big hydro projects: Some controversial issues

We have seen that hydro projects can be small or big. Big reservoir based multi-purpose hydro projects with irrigation canals which generate hundreds of megawatts need to be critically examined for their merits as well as problems.

There is a fierce debate on whether big hydro projects are good or bad. To understand both the critics and the supporters, let us look at the different aspects of this issue, concentrating however only on those aspects of hydro projects related to power generation.

Hydropower is claimed to be clean, cheap and renewable. It is also said that there is a large untapped potential of hydropower in India. Let us look at these claims one by one.

Hydropower is clean: This is true only at the time of power generation. The ecological impact of constructing a big dam on a river can be quite significant. Many villages and large forest areas may be submerged. Livelihoods dependent on the river would be disrupted. Fish and other marine forms in the river will be affected as well because dams would stop the river flow, disturbing their natural migration and other habits. There can be adverse geological impacts due to dams, like floods (for example the 2013 Uttarakhand floods), landslides or earthquakes. Tropical dam reservoirs are known to have high methane emissions due to organic material. Some of these impacts can never be properly quantified nor corrected. All these issues need to be properly assessed before declaring hydro power clean.

Hydropower is cheap: Since water is ‘free’, there is no equivalent of a fuel cost in the case of hydro power. The cost component depending on the level of generation (called variable cost) is very small. (This could include some marginal increase in maintenance cost, etc). But high costs are involved in setting up a big reservoir based hydro station. This cost varies a lot from station to station and can be 1.5-3 times the cost for a coal-based station. The cost will be low if the head of water available is high (that is, there is a high level difference between the dam and the generating station). For big hydro projects, nearly 80% of the cost is for civil works, whereas for small projects the proportion of equipment cost is high. This cost is annualised over the life of the station to calculate the cost of generation per kWh. Thus we hear of values ranging from 10 paise/kWh to 600-900 paise/kWh as the cost of hydro power generation. Why is there such a wide variation?

There are many reasons for this wide variation, in addition to the differences in site conditions (for example, if there is a natural high head, the initial cost is low). Construction related reasons include delays in completing the project and cost overruns. The initial estimate of the time taken for construction and its cost are often very optimistic. The actual construction time and cost are sometimes many times more.

Another reason is the difference in estimating environmental costs and Resettlement and Rehabilitation (R&R) costs. Very often R&R costs are projected very low. Wrong projection of water availability for power generation is another issue. Power can be generated only when water is available in the reservoir and its use for power generation is permitted instead of its use for irrigation, drinking water needs, etc. The cost per unit will be very high if water is available only for a few weeks in the year to generate power. Siltation of the dam and the resulting reduction of water storage, flow and life of the dam are other factors. Reduction of storage reduces power generation. These factors are often not considered while estimating costs and the hydro power cost is thus projected as very low.

Since power generation from a hydro station can vary from minimum to maximum capacity and the generation level can be changed in minutes, they are ideally suited to handle peak or fast variation of loads. But since the operation of a multipurpose project is dictated by the irrigation and water supply needs, not all hydro stations can be used as peaking stations. Also, since many ‘run of the river’ hydro stations do not have adequate storage, it is not possible to use them as peaking stations. Hence the extent of contribution of hydro stations to peak or load variations is subject to many constraints.

Hydropower is renewable: Rivers and water flow are indeed renewable resources. The arrangement to store water in a dam lasts as long as the life of the dam, which can be as long as 50-60 years (sometimes reduced due to siltation). The first point to note is that hydropower is renewable on a year to year basis, but within the year, it is a depletable non-renewable source. Power can be generated as long as there is water in the reservoir. Once the level falls very low, generation has to be stopped till the rains come. The second point is that the station can generate full power for some years after which the storage capacity diminishes due to siltation.

There is large potential for hydropower: As estimated by the CEA, there is a potential of nearly 145,000 MW for hydro power in India of which only 45,000 MW has been developed. This potential includes big and small projects. This estimate is largely based on the identification of available sites of construction for dams. It is essential to learn from the experience of executed projects and to critically study the potential ecological impact before planning big projects. Even though there was enthusiasm to construct many new hydropower projects, in the last few years, this has slowed down.

Table 3.1: Key information for different generation options

Source: Approximate numbers, compiled by the authors from different sources

Notes: (1) Numbers are indicative, (2) Area given is for a power plant of a typical size. For hydro plants, this is the submerged area and this number can vary across projects.

Key information for different generation options is summarised in Table 3.1.

3.1.10 What is new?

There are many new developments in the area of generation. This includes use of new energy sources like tidal or geo-thermal, reducing the environmental impact of thermal power plants, improving conversion efficiency and introduction of grid level storage.

‘Super-critical’ and ‘ultra-super-critical’ coal power plants have higher conversion efficiency and hence require lesser coal and land. Wind solar hybrid plants can achieve a nearly 40% capacity utilisation factor and have lower capital cost since the land and grid connection are shared. Grid level battery storage plants with MW level capacity can help to manage the load generation imbalance. These are expected to become more common with the drop in battery prices. With growing penetration of electric transportation vehicles, there is potential to control the charging demand based on the grid requirements.

3.2. Transmission system

The ‘Transmission and Distribution system (called T&D system)’ is the network that connects generation and utilisation. Transmission and distribution differ in the voltage levels of operation. The transmission system operates at 66 kV or higher while distribution operates at lower voltages up to the consumer location.

In physical terms, the transmission system consists of the power lines, substations and the support systems needed to operate the transmission system. Its operation is coordinated by the State Load Dispatch Centre (SLDC). There are interstate transmission lines which connect all states across the country. Their operation is coordinated by the Regional and National Load Dispatch Centres (LDC).

Most of the transmission systems consist of AC Extra High Voltage (EHV) lines and substations. There are a few High Voltage Direct Current (HVDC) systems, used for transmitting very large power (500-2000 MW) over long (more than 500 km) distances and linking two power systems that operate at different frequencies. In India, HVDC and 765 kV AC lines are used to link up regional systems. See Table 3.2 for the major HVDC links and the inter-regional transfer capacity in 2017.

Table 3.2: Major HVDC links and inter-regional transfer capacity in 2017

Regions

Major HVDC links

Total transfer capacity (MW)

East-North

Champa- Kurukshetra

22,530

East-West

None

12,790

West-North

Mundra- Mahendra Nagar

16,920

East-South

Talchar-Kolar

7,830

West-South

Chandrapur back to back

12,120

East-North East

None

2,860

North-North East

Agra-Biswanath Chariali

3,000

Total

78,050

Source: Ministry of Power Annual report 2017-18

3.2.1 Transmission lines

Transmission voltages are very high and can be AC or DC (See Table 3.3 later in this chapter). Since the voltage is very high, transmission lines are stringed on very tall towers. Transmission towers are 30-50 metres high, as tall as a five-storey building. Lines are connected to towers by a chain of insulators. Typically there are many insulators strung up together. For 132 kV, there can be as many as 10 insulators. Lines run from one tower to another, which are 100-400 metres apart. Usually there are three power-carrying lines (corresponding to three phases) and one or two lines that are lightning arrestors. Lightning arrestors are located at the highest point of the tower and are connected to the tower and via the tower to the ground. A set of three lines is called a circuit. Usually a tower carries only one circuit, but it is not unusual to see towers with two circuits. At very high voltages, every phase may have more than one conductor. Thus you may see a 400 kV line with two or four conductors in each phase. In High Voltage Direct Current (HVDC) lines, there will be two power carrying lines per circuit. Figure 3.6 is a photo of a 765 kV transmission tower with two circuits and with four conductors in each line.

Figure 3.6: 765 kV transmission tower

Photo credit: Prayas (Energy Group)

These towers are expected to withstand rain, sun, wind, and snow. They are designed based on the ground and weather conditions. Since such high voltages are very dangerous, the transmission company compensates the owners for the land around the route of the line and has what is called the ‘right of way’ (RoW). No construction, tall structures or trees are allowed on this route. The approximate power carrying capacity, cost/km and right of way for these lines are given in the Table 3.3.

Table 3.3: Details of transmission lines

Source: Approximate numbers compiled by the authors from regulatory documents and other references

Underground cables can also be used for transmission. They are typically used for short distances, in cities, inside factories, under water, etc where overhead transmission is infeasible.

Figure 3.7: Transmission substation

Photo credit: from Gujarat Industries Power Company Ltd. (GIPCL) website at http://www.gipcl.com/writereaddata/Portal/Images/Energy-Efficiency3.jpg

3.2.2 Transmission substation

A transmission line starts and ends at ‘substations’. The substation is like a railway junction where many railway lines meet with trains arriving on one line and leaving on another. A ‘transmission substation’ is spread over a large area (few acres) with numerous equipment. These include transmission lines, transformers, bus bars, circuit breakers, isolators, protective relays, lightning protection equipment, communication equipment, and a control room. A substation is known by the voltage levels present and the power handled. For the voltage level, the highest voltage level alone may be used or all the voltage levels may be present. Thus, a substation that handles 500 MVA power and has 400 and 220 kV voltage levels, may be called a ‘500 MVA - 400 kV substation’ or better, a ‘500 MVA - 400/ 220 kV’ substation. Figure 3.7 is a photo of a transmission substation.

A ‘transformer’ is used to convert one AC voltage to another. We have seen in Chapter 2 that it is better to transmit power at a high voltage to reduce transmission losses. Therefore, power generated at 10-15 kV at the generating station is converted to a higher value by ‘stepping up’ to a higher transmission voltage using a transformer at the substation. At places where there are load centres including factories and townships, transformers ‘step down’ the voltage to distribution level voltages. Transformers are identified by the upper and lower voltages and the power they handle. At a 220 kV substation, you may find two 220/132 kV transformers, each capable of handling 100 MVA power. Another function of the transformer is to correct for small variations in voltages. By varying the ratio of the number of turns of the winding, a transformer can affect 5-10% change in the voltage output. This is done by ‘Online Tap Changers’.

A ‘Bus Bar’ is a set of lines (one line for each of the three phases) at one voltage level to which many connections are made. Hence, in a 220/132 kV substation there will be one 220 kV and one 132 kV bus bar. All 220 kV lines and the 220 kV terminals of the transformers terminate on the 220 kV bus bar. Similar is the case for the 132 kV bus. In big substations, there can be more than one bus bar at the same voltage level, for example, there can be two 220 kV bus bars. In such cases, there will be a bus coupler, which is like a switch that can be used to connect the two bus bars.

A ‘Circuit Breaker (CB)’ is an elaborate switch used at high voltages and currents. A switch used at home to switch on or switch off a 70 W fan can withstand 240 V, 5 Amperes of current and weighs a few grams. A typical circuit breaker used in a 220 kV substation is designed to withstand 220 kV, 600 Amperes and weighs hundreds of kilograms. A switch is put ON or OFF by a person whereas a CB is designed to also automatically turn OFF when there is very high current, say due to short circuit. CB can also be operated remotely from a control room. In case of a CB, terms like Close/Open and Close/Trip are also used to mean ON/OFF.

‘Protective Relays’ in the substation are designed to sense any abnormal voltages or currents. They send a signal to the CBs to OPEN, thus protecting generators, lines or transformers. Relays at the substation are designed to detect many types of abnormal operation like high current, high voltage, high/low frequency and mismatch in frequency.

An ‘Isolator’ is also a switch. It differs from a CB in that it cannot be operated when there is current flowing in the circuit. As the name conveys, an isolator ‘isolates’. In order to isolate a piece of equipment, first the CB is opened, and then the isolator is opened. Repair works are undertaken only after opening the isolator. Similarly, if an equipment is to be brought back to circuit, first the isolator is closed and then the CB.

In addition to these, substations will have equipment like lighting arrestors to protect the substation equipment, and current and potential transformers to convert the high current and voltage to low levels suited to measuring instruments. Modern substations may have Flexible AC Transmission System (FACTS) equipment. FACTS equipment consists of power electronic based systems designed to control voltages and power flows. This helps to improve voltage, reduce losses, improve the stability of the grid, and increase the power carrying capacity of transmission lines.

Most of a substation’s equipment is located in the open air in the switchyard. This includes the bus bars, transformers, CBs, isolators, lightning arrestors, etc. The new Gas Insulated Substations (GIS) can also be located indoors and need much less space (nearly one-fifth of their open air counterparts), and thus are commonly found in cities. The protective relays, meters, switches for remote operation, communication equipment, control systems, etc are located in the control room. The operation staff present there keep an eye on the meters to sense any abnormal operation, conduct periodic maintenance, records operational parameters and stay in touch with the Load Dispatch Centre using the communication equipment.

A few words about the ‘protection system’ that protects the transmission equipment and ensures the safety of personnel are in order. Transmission equipment may be damaged when very high current flows through it, which in turn happens when there is a ‘Fault’. A fault occurs when two transmission lines touch each other, or if one or many lines touch the ground. This can happen when the lines break or sag, when trees or any conducting object come in their way, when insulators do not work, or due to lightning. The protection system starts acting when a fault occurs. The relays detect the fault and send a signal to open the circuit breakers. The idea is to open up the line as fast as possible to prevent damage. Often the fault incident lasts only for a short while (for example during lightning or an insulator flashover). The circuit breaker closes after some time and if the fault has disappeared, the supply is restored. If the fault persists, the circuit breaker opens again. This cycle (open-close-open) may be tried once or twice to test if the fault has disappeared. If it has not, then the circuit breaker is kept open till an operator attends to it. This cycle of open/close operation to test the fault is called ‘Auto Reclosing’. This is also employed in distribution systems and explains why sometimes power supply is restored after a few minutes of outage.

3.2.3 Working of a transmission system

The transmission system consists of all the substations interconnected by transmission lines. It is like a network or mesh, and is called the transmission grid. In a general fashion, flow of power in this grid can be described as follows: power is fed into the grid at the generating stations; power flows on the lines towards load centres; and finally, the substations near load centres step the voltages down and supply power to the loads. Its working is a bit more complex because of many reasons:

There are many generating stations and load centres.

There are multiple paths from a generating station to a load centre, through the transmission grid (network of lines).

State grids are connected to form a Regional Grid and Regional Grids are connected to form the National Grid.

Power flow on lines is governed by the laws of physics and cannot be easily controlled to follow the contract terms.

The transmission grid is like the network of roads in a city; there is more than one route between two points and traffic flows on all these routes. If for some reason, one road is crowded (similar to a transmission line being overloaded), or closed for traffic (similar to a transmission line being kept OPEN), then people use other roads (similar to the attempts to make power flow through other lines, which is not as straightforward as traffic diversion). Traffic flowing on alternate roads can crowd those roads as well (similar to overloading of more lines). With many generating stations, many load centres and a network of lines connecting them, it helps to look at the grid as a net made of ropes, put up like a tent, propped up by many bamboo poles and a few ropes fastened to spikes on the ground. Please see Chapter 4 and Box 4.4 Grid collapse, blackout and brownout for more details.

3.3. Distribution system

The ‘distribution system’ physically consists of distribution lines and substations. It supplies power to consumers. After power sector reforms (please see Chapters 5 and 9 for more on these reforms), many Indian states have three or four distribution companies. The primary distribution system connects to the transmission system at 33, 22, or 11 kV voltage levels and forms the backbone of the distribution system. The secondary distribution is at lower voltages of 415 V (three phase) or 240 V (single phase) - the voltage at which electricity is supplied to homes.

The distribution system has two functional components -distribution and supply. ‘Distribution’ refers to the physical network that transports electricity from the transmission system to the consumer, while ‘supply’ is a commercial function related to the sale of electricity to the consumer. In India, a license is given for both distribution and supply. In this chapter, the word ‘distribution’ denotes ‘distribution and supply’.

Voltage levels prevalent in India for different systems are given in Table 3.4. The most common voltage levels are indicated in bold letters.

Table 3.4: Typical voltage levels for generation, transmission and distribution

System

Voltage levels

Remarks

Generation

11-28 kV

Mostly 11 kV

Transmission - AC

66, 110, 132, 220, 400, 765, 1200 kV

66 kV is also called sub-transmission

Transmission - HVDC

500, 800 kV

Used for long distances

Distribution - Primary

11, 22, 33 kV

Big consumers like factories and big offices are connected at this voltage

Distribution - Secondary

415 V (Three phase), 240 V (Single phase)

Homes are connected

3.3.1 Distribution lines

Distribution lines consist of overhead lines or cables (which could be underground). Underground cables are common in big cities and inside factories. Unlike transmission lines, which form a mesh (providing alternate paths for power to flow), distribution lines are mostly ‘radial’ in nature. They start from a substation and supply power to a few consumers after which they terminate. This is mostly true in rural areas. In cities, taking advantage of the high load density and in order to increase the reliability of supply, primary distribution can have a mesh like connection, often called ‘ring main’, with a ring of connected substations located at different locations in the city. In cities, it is also possible to supply power through different routes, though at a time, only one route is used.

The height of the distribution poles varies with the voltage of the line they carry. 33 kV lines are carried on 8-10 metre tall (around 30 feet) poles, whereas the 11 kV or 415 V lines are carried on 7-9 metre tall (around 25 feet) poles. Figure 3.8 shows 11kV distribution lines under construction (left) and a distribution transformer (right).

Figure 3.8: Distribution lines under construction; Distribution transformer

Source: Prayas (Energy Group)

3.3.2 Distribution substation

‘Distribution substations’ are smaller than transmission substations, with a 33 kV substation occupying a few hundred square yards. Such a substation would have one or two transformers and 3-4 feeders of 11 kV voltage connected to it. The roadside structure with a Distribution Transformer (DT) is an 11 kV substation and it will have 4 wires at the output. Three of them are phases and one of them is the neutral. Voltage between phases is 415 V and between a phase and neutral it is 240 V. Equipment in a distribution substation is a smaller version of that present in a transmission substation. Table 3.5 gives typical data about distribution lines, including the power carrying capacity, pole height and cost.

3.4. How is power utilised?

At a broad level, the 25 crore electricity consumer connections in our country can be divided into five major categories: domestic, commercial, industrial, agricultural, and other (covering railway traction, street lighting, water supply, etc). Their combined consumption in 2015-16 was over 1,000,000 Million Units (10 lakh MU), with industry being the biggest consumer. Table 3.6 gives the category-wise breakup for the percentage of consumers, connected load, consumption and revenue.

Table 3.5: Distribution lines: Typical parameters

Voltage kV

LT-0.415 kV

HT-11 kV

HT-33 kV

Pole height (metre)

7-9

7-9

9

Span (metre)

60-65

60-65

80-100

Power capacity (kW)

25-100

2000-3000

40,000-50,000

Cost (Rs lakhs/ckt km)

3-4

4-6

5-7

Notes:

1. These are approximate numbers compiled from various sources like the report prepared by Administrative Staff College of India (ASCI) on capital cost benchmarks for distribution, prepared for the Forum of Regulators in 2010 (http://www.forumofregulators.gov.in/Data/study/capital-cost-banchmarks.pdf) and regulatory submissions.

2. Cost of an underground cable is around 8-10 times that of overhead lines for 11 and 33 kV; it is 2-5 times for LT.

3. A Distribution Transformer costs around Rs 1-2 lakh and a 33 kV substation around Rs 150-200 lakh.

Table 3.6: Breakup of consumer numbers, connected load, consumption and revenue

Source: Consumer numbers, consumption and connected load data is for 2015-16 from CEA annual statistics (2017), and the revenue data is for 2015-16 from the PFC report on performance of state power utilities for 2014-2016. Revenue data does not include some private utilities (like Mumbai, Kolkata, Ahmedabad and Surat), and hence can be taken as indicative.

Domestic consumers top the number of connections and connected load, though they consume only 24% of the total energy. It can also be seen that industry, which accounts for less than 2% of the connections, consumes nearly 42% of the total energy consumption and contributes nearly half the revenue. This includes small, medium and big industries. The pattern of consumption has changed over the years, as can be seen from Figure 3.9.

Figure 3.9: Changing pattern of electricity consumption

Source: CEA report, “Growth of electricity sector in India, 1947-2017”

Electricity consumption has grown nearly 270 times from 1947 to 2018. At the time of independence, industry was the major consumer of electricity. As can be seen from Figure 3.9, over the years, the percentage consumption of industrial consumers reduced, whereas that of domestic and agricultural consumers increased. Efficiency improvement in industrial electricity use, growth of the services sector, state supported growth of electricity based irrigation and rural electrification have contributed to this change in electricity use pattern.

It is interesting to note the pattern of electricity consumption in the domestic sector. An approximate analysis indicates that, of the total electric energy consumed by all homes, nearly half is used for lighting and fans. The rest is used for refrigeration (17%), water heating (12%), TV (11%), cooler or AC (7%) and other services (5%).²² Electricity consumers use a variety of appliances like bulbs, tube lights, motors, pump sets (with a motor) etc which consume electricity. An indicative list is given in Table 3.7. These different uses can be divided into three broad classes - a) motors, b) electrolysis and heating and c) lighting and other. Nearly 75-80% of electricity is consumed by motors, 10-15% of electricity is used for electrolysis and heating, and 5-10% for lighting and others.

Table 3.7: Appliances used by different categories of consumers

S No

Consumer category

Appliances used

1

Domestic

Lights (bulbs, tube lights, CFL, LED lamp), fans, TVs, fridges, mixers/grinders, water heaters, electric irons, air coolers, ACs, water pumps, ovens, electronic appliances (computers, mobile charging, etc), elevators

2

Commercial

Lights (including neon signs), fans, air coolers, ACs, fridges/cold storage, TVs, computers and communication equipment, electronic appliances (XRay/MRI machines in hospitals, etc), elevators

3

Agriculture

Pumpsets, lights, cold storage, agriculture processing machinery

4

Industry

Lights, fans, different kinds of motors, heaters, electrolysis, computers and electronic equipment, elevators, cranes

It must be clear by now that electricity means different things to different consumers. Water pumping for irrigation in agriculture is a major end use in India (See Box 3.4).

Box 3.4: Agriculture water pumping as a major electricity end use

Growth in irrigation has catalysed a significant increase in food production after independence. Nearly 80% of the water use in India is for irrigation. Groundwater irrigation plays a major role compared to canals and tanks. Tank and canal based irrigation dominated till about 1975, when groundwater based irrigation overtook these irrigation methods to support the highest irrigated area. Since tank based irrigation slowed down and canal irrigation grew at a slow rate, today groundwater based irrigation supports twice the area irrigated by canals and tanks put together. While it is important to promote rain-fed agriculture, reviving community tanks and selective use of canals, it is important to realise that groundwater based irrigation holds the key to food security in this country.

And what powers groundwater irrigation? It is reported that there are around 2.8 crore pump sets in India. Nearly 2 crore of these run on electricity and the rest use diesel. A very small number are manual/animal operated or more recently powered by solar. The annual growth rate of the number of electricity based pumps is around 3-6%. It is clear that electric-operated irrigation pumps are the drivers of groundwater based irrigation. Electricity consumption by these pumps is around 17-18% of the total consumption in the country, a close third after industry and domestic sectors. It is also to be noted that the percentage of agriculture consumption is as high as 30-40% in some states.

There are also many challenges in electricity supply to agriculture. Agriculture connections are often not metered, and hence there is significant uncertainty in the reported estimates of electricity consumption by pump sets. Tariff is low and in some states free, leading to neglect of efficiency and high use of electricity and ground water. Most states provide only 7-10 hours of supply to agriculture, often during off-peak hours. Even during this time, there are many power interruptions, and long delays in restoring supply.

There have been few initiatives by the distribution companies to address these issues. ‘High Voltage Distribution Systems (HVDS)’ aim to reduce the length of Low Tension lines supplying power to agriculture. Small distribution transformers of 25 kVA capacity are used to supply power to a few pump sets. This is expected to improve voltage and reduce technical losses as well as theft. This has been tried in many states, with mixed results. Feeder separation involves delinking power supply to agriculture pumps from the supply to villages. In some states like Gujarat and Maharashtra, separate 11 kV feeders are laid to supply the pump sets. This program is being extended to the rest of the country as well. This helps the distribution company to effectively restrict hours of supply to agriculture and simultaneously improve the quality of power supply in rural areas.

Moving ahead, we will look at the utilisation of electricity, first from the consumer’s point of view and then from the point of view of those operating the power system.

3.4.1 Utilisation: Consumer point of view

Consumers are keen to have electricity when needed and in good quality and at suitable price. They are also keen to ensure that electricity use does not lead to any accidents.

Calculating power consumption

An electricity bill is calculated using the energy consumed in a billing period, which is typically one month. For big consumers, the charge may depend on the amount of connected load (measured in kW or kVA), time of use of electricity, power factor, etc. Details of how the electricity charge is determined are given in Chapter 7. Here, we look at the energy consumption levels of different kinds of electrical appliances.

The electrical energy consumed (in kWh or units) by a piece of machinery or appliance in a month of 30 days can be calculated if we know the power in watts and the number of hours of use. Thus, if a 40 W tube light is used from 6 in the evening till 10 at night every day, that is, four hours per day, the monthly consumption will be:

Monthly consumption in units:

(40 W × 4 hours × 30 days)/1000 = 4.8 kWh or 4.8 units.

Tables 3.8 and 3.9 show the typical appliances, daily hours of use and monthly consumption of a small two-room house and a big five-room house.

Table 3.8: Small house electricity consumption

Source: Approximate numbers compiled by the authors

Table 3.9: Big house electricity consumption

Source: Approximate numbers compiled by the authors

It can be seen that the appliances with high wattage or long hours of use contribute the most to monthly electricity consumption. For example, consumption by air conditioners form 47% of the total consumption in a big house. Small houses similar to the example in Table 3.8 account for nearly half the number of domestic consumers, whereas big houses similar to the example in Table 3.9 constitute 2-3%. Refer to Annexure 3.1 for the typical electricity consumption of some common domestic appliances. This can be used to approximately calculate your electricity consumption.

Factories and offices use many kinds of appliances. The power needed is normally mentioned on the name plate of the equipment. We could calculate the monthly energy consumption after ascertaining the power rating of the equipment, their numbers and the hours of use. This can be checked against the standard values of energy consumption for shops, process industries, offices, etc depending on the size of the operation. For example, a textile shop with 300 square feet area may have a monthly consumption of about 1000 units. The aluminium industry consumes around 36,000 units per tonne of production, whereas the cement industry consumes around 80 units per tonne.

Electronic equipment and computers require quality power and hence are connected to Uninterruptible Power Supply (UPS) systems. Similarly, many consumers use ‘inverters’ to overcome power cuts. UPSs and inverters have battery backup, which is charged using grid electricity.

How can we reduce consumption?

Since electricity generation has adverse impacts on natural resources, the environment and livelihoods, it is important to minimise wastage and increase efficiency. Use electricity only when it is required and as efficiently as possible. Use natural lighting and cooling methods as much as possible. LED lamps and tube lights are much more efficient than ordinary bulbs.

Switch off the lights and fans when they are not needed. Switch off water heaters after a few minutes and adjust the settings on refrigerators or ACs based on the season. For TVs, set-top boxes and computers, it is better to switch off the power supply, rather than putting them on stand-by using a remote. Annexure 3.1 shows that there is power consumption even in stand-by mode. To reduce the electricity bill, focus on the appliances which have high wattage or high hours of operation. In a small house, it will be the TV and fans. In big house, it will be water pumps, air conditioners, and refrigerators.

The potential to save in offices and factories is much higher. Motors that are properly sized to the requirement of the application will save more energy. A similar approach applies to turning off unwanted motors, insulating pipes carrying hot/cold fluids and plugging energy leakages. It is estimated that on average about 15-25% energy saving is possible in most industries. We shall come back to this issue in Chapter 8.

The Bureau of Energy Efficiency (BEE) has introduced star rating for appliances like fans, refrigerators, water heaters, air conditioners, agriculture pumps, etc. Labelling is mandatory for some appliances (refrigerators, air conditioners, tube lights, colour TVs, water heaters, and LED lamps) and voluntary for some others (fans, pumpsets, washing machines, laptops, printers and inverters). The rating system can help consumers gauge the energy savings of certain appliances. For example, a 5-star rated refrigerator consumes only 40% of the electricity consumed by a 1-star rated refrigerator, and a 5-star rated agriculture pump set consumes about 80% of the electricity consumed by a 1-star rated pumpset.

Quality of supply and service

It is important that consumer interests are protected and that the consumer performs her duties. Consumer interests include reasonable tariff, good quality supply and service, prevention of electrical accidents, and protecting electrical appliances from bad quality power. The consumer’s duties include paying bills on time, observing safety precautions and not indulging in theft of electricity. Tariff issues are covered in detail in Chapter 7, and other issues are covered here.

Power supply quality is based on voltage variations, supply interruptions, frequency and harmonic components (presence of frequencies other than the standard 50 Hz in the system). From the consumer point of view, frequent power outages, very high voltage, low voltage or frequency variations can damage the appliances or reduce their life. Service is related to restoring supply after an outage, issuing correct bills on time, as well as addressing consumer requests or complaints in a timely manner.

The Distribution Company (DISCOM) is expected to provide electricity supply and service that meets some specified standards. For many years, supply quality standards were based on the 1956 Indian Electricity Rules, but now supply quality and service standards are set by the respective State Electricity Regulatory Commissions. These institutions are covered in Chapter 5, and Table 3.10 gives the typical applicable supply standards for voltage, frequency and harmonics. The limits indicate the range within which a parameter is to be maintained. For example, LT supply voltage - expected to be 415 V - can vary between 390 to 440 V, that is +6 and -6% of 415 V. Table 3.11 gives the typical applicable standards for a few service parameters. For example, if a power failure is reported by a consumer in a city, the DISCOM is expected to restore power within 4-6 hours, or else, Rs 50-100 compensation is to be paid to the consumer. If the supply or service quality is bad, the consumer can complain to the DISCOM, the Electricity Consumer Grievance Redressal Forum, and the Electricity Ombudsman, as described in Chapter 5.

Table 3.10: Typical supply standards

Parameter

Limits %

LT supply voltage

+/- 6

HT supply voltage

+6 and -9

EHT supply voltage

+10 and -12.5

Frequency

+1 and -0.2

Harmonics 132 kV

3

Harmonics 33 kV

8

Harmonics 11 kV

8

Source: Approximate numbers compiled by the authors from Standards of Performance Regulations of different states.

Table 3.11: Typical service standards

Source: Approximate numbers compiled by the authors from Standards of Performance Regulations of different states.

Safety of people, animals and appliances

The Central Electricity Authority (CEA) specifies the safety requirements for construction, operation and maintenance of electric lines. Distribution companies are expected to follow the 2010 Central Electricity Supply Measures relating to safety and electricity supply regulations. This covers provisions the company must make, such as employing electricity safety officers who carry out periodic safety inspections, and maintaining updated maps of electricity lines. It also includes general safety requirements like measures to ensure safety of humans, animals and property - like earthing, danger notices, location of junction boxes at home or in the street. Another section covers general conditions of supply, like safe insulation levels, test procedures and safety provisions for installations and appliances, including testing insulation and earthing. Safety requirement for overhead lines and underground cables (joints, minimum clearance above the ground, minimum clearance from building, clearance between conductors on a pole) are also included.²³ The Electricity Act, 2003 (E Act) requires that each state set up an office of the Electrical Inspector. Functions of the electrical inspector include enquiry into electricity accidents and carrying out safety inspections.

Electric shocks can be fatal. Lightning is nature’s game of electricity and can kill people or devastate buildings and trees. Tall buildings and towers are protected from lightning by lightning arrestors. A current flowing through the human body causes an electric shock. When the body comes in contact with a bare conductor at a certain voltage, current flows through the body. This current is given by Ohm’s law (See Chapter 2):

The human body is around 60% water and is covered by a thin dry skin. Most of the body’s resistance is in the skin. Resistance varies a great deal from person to person and changes a lot depending on the wetness of the skin. Resistance of dry skin varies from 100 kilo ohms to 500 kilo ohms, whereas that of wet skin is only 1 kilo ohm. Within the skin, the body’s resistance is just about 500 ohms. Therefore, even small voltages can cause shocks, if the skin is wet or exposed due to a wound. People sometimes test a 1.5 V ordinary cell by putting their tongue on the terminal!

A current of 10 milli Amperes can cause a tingling sensation while 20 milli Amperes can cause a painful shock. Damage caused due to the shock depends on the amount and the path of the current. Typically the hand touches the wire and current flows from the hand, through the body to the ground through the feet. A shock can be fatal if the current value is more than 100 milli Amperes or if the current flows through the heart.

Electrical short circuits can also create sparks, leading to fire. The number of deaths due to electricity shocks and fires are documented by the National Crime Records Bureau (NCRB). Figure 3.10 shows the increasing number of fatal human accidents due to electricity. In 2015, more than 12,000 people died due to electricity accidents.²⁴ Most of these accidents happen in rural areas. Most states provide ex-gratia for fatal electricity accidents involving people or animals. With the increase in rural electrification, it is important to study the causes of such accidents, analyse the trends and take steps to minimise them.

Figure 3.10: Increasing electricity accidents

Source: Compiled by the authors from annual reports on Accidental deaths and suicides in India, prepared by National Crime Records Bureau.

Some steps can be taken to reduce the hazard of shocks. Bodies of all the appliances are connected to the earth as part of electrical wiring. This is done by connecting a wire from the body of the appliance to an earth pit - a deep hole in the ground which is near the premises. This reduces the chances of an electrical shock to a great extent. To make the earthing effective, it is essential to use three-pin plugs for such appliances (refrigerator, electric iron, mixer, washing machine, etc). To set up proper earth wiring, the body of the equipment must be wired to the third pin - the biggest of the three pins - and then to the earth pit, and the earth pit should be maintained with occasional watering and cleaning of terminals. While carrying out repairs, it is essential to switch off the main switch, ensure that the wires are not exposed, and wear rubber footwear. Plug points and switches should be covered and out of reach of children. Earth leakage circuit breakers are available these days, which open the moment anyone in the premises touches a live wire and the current starts flowing to the ground. The DISCOM also has to ensure that the lines and transformers are constructed and maintained according to safety standards. This includes fencing of transformers and maintaining a minimum distance from ground and buildings. They are also expected to conduct periodic safety audits.

Appliance protection is another major issue. Circuit breakers and fuses can prevent high current from damaging the appliances and house wiring. A fuse is a thin wire that melts and thus stops the current if the value of the current is too high for too long. A circuit breaker, as seen earlier in the chapter, is a sophisticated switch that can open on its own if the current is high. It is essential to ensure that the right kind of fuse and circuit breaker is used to protect equipment. Electronic items like computers get damaged if the voltage fluctuates too much or if there are frequent power interruptions. Uninterruptible Power Supply (UPS) is used to protect such equipment.

One should be familiar with some key parts of house wiring and simple testing and measuring instruments. Electricity from the DISCOM is first connected to a switch board at the consumer premises. The first connection is to the electricity meter, which is usually located at such a place that the DISCOM official can read it even if you are not at home. It is sealed and you are not supposed to tamper with it. From the meter, the next connection is to a fuse unit, main switch or a Miniature Circuit Breaker (MCB), from where connections are made to the appliances in your home. Small houses and shops have single phase connections, with only two lines - one live wire (called phase) and a neutral wire. Three phase connections consist of four lines - three phases and one neutral.

A tester is a simple instrument to check the presence of supply and it should be used only when your hands are dry. A multi-meter is an instrument which can measure voltage, current and resistance. Electricians also use instruments like a clamp-on metre to measure current consumed by an appliance (without changing any wiring), a megger to measure insulation resistance, and earth resistance measuring equipment to check the quality of earthing.

3.4.2 Utilisation: The point of view of those who operate the electricity system

The electricity sector consists of different actors (or departments) which look at the electricity utilisation by consumers from different perspectives. These actors include the distribution substation, transmission substation, state load dispatch centre, planning department, meter reading section, revenue collection section, policy makers, regulators, complaints handling forums, and the safety department. Chapter 5 describes these actors and their functions. Without getting into the details of who does what, we describe here three important issues that the DISCOM (the sector’s primary interface with the consumer) is concerned with in the area of utilisation: load behaviour, quality issues and safety issues.

Load behaviour

The power required to operate an electrical appliance is called ‘Load’. As explained earlier (Box 2.5 in Chapter 2) load is made up of an active part (measured in Watts) and a reactive part (measured in VARs). Resistive loads like ordinary bulbs, heaters, etc do not need any reactive power. But motors, which make up the majority load for a DISCOM require reactive power. Usually, load refers to active power and most of the discussion below is about active power load.

One more clarification on load is in order. Depending on consumer behaviour, the load keeps changing from second to second. This load is called the ‘Instantaneous Load’. The instantaneous load can be quite erratic, with sudden rises and falls. Therefore, most often, the instantaneous load is averaged over a period of 15 or 30 minutes for accounting purposes. This helps to smoothen out the effects of sudden erratic changes. Hourly load is the load averaged over one hour. Load at an hour, say 10 AM (which is 1000 hours), is the average of the instantaneous values of load (measured, say every 10 seconds) from 0930 to 1030. Calculating the energy from average hourly load values is straightforward. It is enough to add up all the hourly loads in a day to get the energy consumption. For all practical purposes this averaged value of instantaneous load is what is called the load.

The load curve is a graph showing the value of total active power load for a DISCOM at different points of time in a day. The load curve changes shape across different days and seasons. Table 3.12 gives typical hourly load data for a state for the day with the highest peak demand in 2017, and Figure 3.11 shows its graph.

Table 3.12: Hourly load data

Figure 3.11: Hourly load curve

Source: Compiled by the authors from the Annual report of a Regional Load Dispatch Centre

The load depends on the kind of appliances consumers use and the time they turn them ON. Hence the value of the load is not exactly predictable beforehand, but a reasonable forecast can be prepared based on historical data and some correlations (with weather, festivals, etc). This is quite like road traffic conditions. It is not possible to predict exactly how busy the traffic will be at any given day and time. But based on previous experience, one can make some reasonable observations about traffic just as one can about load (See Box 3.5 A parallel to road traffic). As the graph shows, the value of the load keeps changing from hour to hour. There is a peak in the evening at about 4 PM, as also shown in yellow in Table 3.12. The lowest value occurs after midnight at 4 AM, shown in green in this table. In the morning, load increases till about 7 AM and then reduces a little, only to steadily increase again.

This is a typical pattern of a daily load curve for many states in India. There are two peaks, one in the early morning and another in the evening. There are two off-peak periods, one in the early morning and another late at night. This behaviour is largely due to the high lighting load in the evenings and the pattern of supply to agriculture pump sets. The state load curve pattern is different in the winter and rainy seasons. For cities like Delhi or Mumbai, usually the peak load happens near noon due to the high air-conditioning load, which can form 30-40% of the total city load. Heating load in the morning, especially during winter, can result in peak load in northern cities. There is a wide difference between summer and winter load curves in cities.

Load values will be lower on Sundays, industrial holidays and national holidays. Since irrigation and air conditioning loads are high during the summer, the load value in the summer will be the highest in a year in most states. It is possible to predict such trends. But some uncertainties would remain and load may change without any pattern as well. There has to be sufficient generation to meet the load. If it is not possible to meet the load, the DISCOM enforces power restriction or power cuts, shutting off power supply to some consumers.

The energy required in Million Units (MU) for the whole day is calculated by adding up the hourly MW load values and dividing it by 1000. In the example given here, the hourly MW values add up to 501,560 and therefore, the daily energy requirement is equal to 501.6 MU. An energy restriction or energy cut (which implies shutting off some loads for a few hours) is introduced if the generating plants cannot generate as much energy in a day as required by the daily load curve.

The average load is calculated by dividing the sum of hourly loads by 24 and is equal to 501,560/24 = 20,898 MW. Thus, if the load is equal to the average value for all the 24 hours, energy consumed in this period of 24 hours will be the same as before, that is 501.6 MU. The ‘Load Factor (LF)’ is the ratio between the average load and maximum load. LF is usually given in percentage and in this example the LF is 92%.

Box 3.5: A parallel to road traffic

Consider a road leading from a suburban residential area to the heart of the city. The traffic will be busy in the morning during rush hour, then will slacken during the day, pick up again in the evening and stay low at night. In the course of a week, traffic will be less on Sundays and holidays. In the course of a year, traffic will reduce when schools close, when there is heavy rain, but increase around festival time. Over the years, traffic will continue to grow since more people will keep buying vehicles.

Load in MW can be compared to the number of vehicles crossing a particular point on the road at a time. Imagine that there is a gate near the residential area where you sit and watch vehicles passing by. The flow of traffic will vary through a 24-hour period, and you can draw many conclusions from the pattern of traffic.

The peak traffic is in the evening between 5.30 PM and 6.30 PM. The minimum traffic is at midnight. You may observe that different types of vehicles peak at different hours. For example, two-wheeler traffic peaks around 7 pm, three-wheeler around 8 am and four-wheeler around 6 pm. The number of vehicles per hour is similar to the electrical load (in MW), and an analogy can be drawn between different vehicles and different types of electrical consumers. The total number of two wheelers, three wheelers and four wheelers in a day as well as the total number of vehicles in a day can be calculated. This is similar to the energy consumption.

This parallel helps us to understand demand restriction and energy restriction as well. If the road is narrow, the number of vehicles that can pass at a time reduces and this is similar to putting a demand restriction. The width of the road also restricts the number of vehicles that can pass the road in a day (provided the pattern of traffic is similar); this is similar to energy restriction. Using this analogy, you can see that even with demand restriction, if the pattern of consumption can be changed, it is often possible to avoid energy restriction. A traffic jam is like an overload or a congestion in the power system.

From the traffic parallel, we can see that the peak traffic for different types of vehicles does not occur at the same time. Similarly, in the power system, all consumers do not have peak load at the same time. This is quantified using the ‘Diversity Factor’. If all consumers peak at the same time, then the diversity factor will be 1. If the peaks occur at different times then the diversity factor would be greater than 1, which is beneficial for the DISCOM.²⁵

Figure 3.11 shows the load curve for one day. In order to analyse the power system over a longer period of time, say one year, a load duration curve is more useful. The load duration curve for a year shows the number of hours in a year that the load is equal or more than a given MW value. It is plotted with load in MW on the vertical axis and hours on the horizontal axis. To plot a load duration curve for one year, one needs hourly load values for the whole year. There are 8760 hours in a normal (not leap) year and therefore there will be 8760 loads. Arrange them in descending order and plot the graph as shown in Figure 3.12. It can be seen that the maximum annual load of about 22,000 MW occurs during a few hours in the year. Throughout the year (for all 8760 hours), however, the load is greater than 11,800 MW.

Figure 3.12: Load duration curve

Source: Compiled by the authors from the Annual report of a Regional Load Dispatch Centre

The DISCOM has to purchase power generation to meet all load. We have seen that all the power generated does not reach the consumers because of transmission losses. The DISCOM has to compensate for these losses by purchasing more power than what is required by all the consumers put together. It has to be prepared for sudden changes in load and the fact that all consumer loads do not peak at the same time. The DISCOM has also to be prepared for the fact that the load curve varies a lot from season to season. Agriculture pump sets will not be operated when it rains and fans will operate for a longer time in the summer. Generation has to be planned to meet these seasonal variations of load. Since renewable generation has near zero marginal costs (marginal cost is the cost for an additional unit of generation) and therefore has a ‘must-run’ status, the DISCOM is mandated to purchase all the renewable power generation. The load to be met after subtracting the renewable power generation is called the ‘net load’ and the DISCOM has to plan to purchase power to meet the net load.

A wide variation between peak and minimum load in the load curve is not comfortable for the DISCOM, which has to purchase sufficient generation, and ensure sufficient transmission and distribution capacity to meet the peak load. During non-peak periods, this capacity will be idle and therefore a waste for the DISCOM. Therefore, DISCOMs prefer a flat load curve. If the load variations are too high, it may take Demand Side Management (DSM) actions to make the load curve flatter. In simple terms, DSM involves switching OFF some loads during peak hours and switching them ON during non-peak hours. See Chapter 8 for more on DSM.

3.5. Dancing to one tune: The grand show that goes on and on

The previous sections have provided an overview of all the major components of the power system. It is clear that these components are interconnected. In the modern world, a healthy power system is a basic necessity which supports societal well-being. The power system encompasses entire states and in some cases involves components across countries. Its smooth and optimal operation is therefore a non-trivial task which can only be achieved through proper planning and operation.

Planning should ensure that all components - generation, transmission, distribution, control, human resources and support facilities - grow in a coordinated manner to meet the increasing demand. The planning aspect is discussed in Chapter 8.

Proper operation ensures that the load is met at all times, no equipment is overloaded, and resources are optimised. The operation is coordinated from control centres, which collect up to date information and issue control instructions. These instructions can be hour to hour changes in generation levels, orders to switch off lines for maintenance, or suggestions for routine maintenance of generators. These are covered in Chapter 4.

Coordinated planning and operation is what ensures that the complex power system dances to one tune, to put up a grand show of serving the country.

Annexure 3.1 Typical appliance consumption

Table 3.13: Typical appliance consumption

Endnotes

¹ The flow battery is an exception, which involves pumping of electrolytes, and hence has moving parts.

2 Frequency depends on the speed of rotation and the number of magnetic poles in the rotor and is given by: frequency = (number of pole pairs X speed in rpm) / 60. One North and South pole together constitute a pole pair. Generators in hydro stations rotate slowly and have a larger number of pole pairs, whereas thermal and gas generators will have fewer pole pairs to ensure that they generate power at 50 Hz.

³ It is another matter that only about 10-15% of the coal used for power plants is now washed.

4 Most coal based units do not usually operate below 70% of their installed capacity. In 2016, CERC has notified that all Central Generating Stations or inter-State Generating Stations will have a technical minimum of 55% of MCR (Maximum Continuous Rating) loading or installed capacity of the unit (see 6.3 B of the regulation available at: http://www.cercind.gov.in/2016/regulation/124_1.pdf ). States are yet to adopt this norm for state generators. This regulation is to accommodate variations in load and generation and will help in the integration of renewable sources. Nuclear based units generally do not change their generation levels, except for maintenance reasons. Gas based stations are capable of operating at low power output.

⁵ Average Capacity = Annual Energy in MU / 8.76 (In the case of a leap year, divide by 8.784 instead of 8.76).

⁶ A high PLF indicates that the generating unit is utilised most of the time. A low PLF indicates that the unit is idle most of the time. Base Load Generating Units (which operate during most hours) have a PLF in the range of 90-95%. Peak Load Units (which operate only during peak hours) have a PLF in the range of 5-10%, and Intermediate Load Units (which run during some peak and non-peak hours) have a PLF of 30-75%.

⁷ Standard Test Conditions (STC) is an industry standard to indicate the performance of solar PV modules and specifies standard temperature (25 degree Celsius), solar radiation of 1000 W/square meter, etc. This condition approximately represents solar noon near the spring and autumn equinoxes in the continental United States with the surface of the cell aimed directly at the sun.

8 After the MoEFCC notification in 2015 on the new environmental emission norms of thermal plants, FGD is essential for new and existing plants. The cost of removing sulphur oxides can be as high as Rs 0.5 crores/MW, or 8-10% of the construction cost of the plant. The CEA has brought out the technical norms for retrofit FGD systems for 500 MW plants in 2017, available at http://www.cea.nic.in/reports/others/thermal/tetd/sts_fgd_tpp.pdf.

9 See the 2007 CEA report on land required for thermal power plants. Page 15 mentions that 2 million tonnes of ash is produced from a 1000 MW plant in a year, which works out to 5.5 tonnes/day/MW. The report is available at http://www.cea.nic.in/reports/others/thermal/tpm1/land_requirement.pdf.

¹⁰ For example, see the CEA report on fly ash generation and utilisation 2014-15, available at http://www.cea.nic.in/reports/others/thermal/tcd/flyash_final_1415.pdf.

11 Most Indian coal plants employ what is called ‘sub-critical’ technology, which means that they operate at lower temperature and pressure, and are typically of capacities less than 500 MW. Higher capacities and efficiencies are possible with new technologies like ‘super-critical’ (40-45%), ultra-super-critical (45-48%) and advanced ultra-super-critical (50%) power plants. The critical temperature and pressure for water is 374 degree centigrade and 226 kg/cm2. Beyond this point, there is no difference between liquid and gas forms of water. A boiler which operate above this temperature and pressure is called a super-critical boiler, which typically operates at 600-610 degree centigrade temperature and 270-300 kg/cm2 pressure. India’s first super-critical coal plant was commissioned in 2010. 40% of thermal capacity addition in the 12th plan (2012-17) and all capacity addition after then was planned to be of super-critical or better technology.

¹² In December 2015, the Ministry of Environment, Forests and Climate Change (MoEFCC) tightened the emission norms for thermal power projects related to emission of particulate matter (nearly 40% reduction), sulphur oxide and nitrogen oxides, as well as water use (nearly 33% reduction). These were to be implemented for existing and new plants by end 2017, but the deadline has been revised to 2020-24. There are various estimates of the cost for complying with these norms, like Rs 50-75 lakh/MW, Rs 1.25-1.5 crore/MW + Rs 30 lakh/year operational expenses (as per Association of Private Power Producers), leading to a tariff increase of Rs 0.5-1.25/Unit. Implementation of these norms is under discussion and it has been suggested that the cost should be passed on to the consumer.

¹³ Efficiency levels of OCGT and CCGT have been improving and as of 2017, these are in the range of 40% and 60% respectively (https://www.iea.org/etp/tracking2017/naturalgas-firedpower/).

¹⁴ See the energy balance diagrams for countries available at the International Energy Agency (IEA) website, for example, https://www.iea.org/Sankey/index.html#?c=France&s=Balance.

15 The formula is: Power = 0.5 x Air density x Area x Cube of velocity.

¹⁶ This is for the commonly used poly or multi crystalline PV. Thin film panels may take up to 1.5 to 2 times that area.

¹⁷ This is a conservative estimate, assuming an average 4-5 units of generation/kWp/day.

¹⁸ Co-generation, also called Combined Heat and Power (CHP), is the production of two forms of energy from one fuel. One of the forms of energy produced must always be heat and the other may be electrical or mechanical energy. This increases the overall efficiency of the plant. In the case of sugar mills, bagasse (around 0.3 tonne produced per 1 tonne of sugar cane crushed) is used as a fuel to generate steam (used to dry sugar) and electricity.

¹⁹ The 13% of hydro installed capacity is based on 344 GW capacity of utilities. If captive is also included, total installed capacity (as of March 2018) is 399 GW and hydro capacity is only 11%.

20 For example, see the frequently asked questions and the answers to the same as provided on the Ministry of power website https://powermin.nic.in/en/content/faqs-hydropower.

21 See minutes of the meeting on the operationalisation of existing pumped storage plants, Central Electricity Authority (CEA), 2017, available at http://www.cea.nic.in/reports/others/planning/resd/mom_pump_storage_plants.pdf.

²² These are approximate figures based on surveys. Proper load research should be done to arrive at more accurate figures.

²³ Some relevant clearances for Low Tension lines which supply electricity to homes: Distance from the ground = 15-19 feet, distance from a building = 4 feet.

²⁴ The CEA and some DISCOMs also report electricity accidents, but these numbers are usually lower than those reported by the National Crime Records Bureau (NCRB). The NCRB reports electricity accident data on an annual basis, while the CEA and DISCOMs report on a financial year basis.

²⁵ To calculate the diversity factor over a period of a year for 3 consumers, say C1, C2, C3, use the following method. Get the individual peak load of each of them as PDC1, PDC2 and PDC3. Let PDS be the system peak demand for the year. Then the diversity factor = (PDC1+PDC2+ PDC3) / PDS. In urban areas, for individual domestic consumers the diversity factor is around 2 (it is less for commercial and industrial consumers), for distribution transformers it is around 1.4, and for substations it is around 1.1. Thus, in a distribution system, the global diversity factor is the product of all these, equal to 3.1.

4 : A brief tour of the electricity sector

Chapter 2 has introduced the major concepts and Chapter 3 described the components of the power system. How does this power system work - minute to minute and day after day? What goes on in generating stations, substations, load dispatch centres and offices of the companies? What is T&D loss, AT&C loss and how does a nation-wide grid failure happen? We try to answer such questions in this Chapter. Planning for longer term - years ahead - is the subject of Chapter 8, on planning.

We have seen in Chapter 2 that the power system has three technical subsystems and many components. The subsystems are:

Distribution and supply, which is the first link to the consumer

Transmission, which carries bulk power

Generation, which is the stage at which power is produced

Chapter 3 has described each of these subsystems. A classic definition of the power system applicable to a large inter-connected system with many big generating stations and centralised control involves these three subsystems. The power system could also be a small stand-alone system (a micro grid) with a small generating station supplying electricity to limited loads located close to it. It may be possible to connect this small system to the larger state level system to enable interactions between the two. All the subsystems should work in close co-ordination to meet the objective of the power system, which is to generate electric energy in sufficient quantities at the most suitable generating location, transmit it in bulk quantities to the load centres, and then distribute it to the individual consumers with satisfactory quality, at the lowest possible ecological and economic price.¹ In this chapter, we take a brief tour of the technical subsystems of the power sector to broadly understand the working of the interconnected power system: What are the events which take place minute-by-minute and the operations which are carried out day-by-day? What happens in the foreground and the background? What are the practices followed currently, and what are the upcoming trends? The behaviour of the power system in a longer time frame (year-to-year) is the topic of Chapter 8 which is on overall planning of the sector.

We start at the consumer end, with distribution and supply, followed by transmission and generation. The last section covers the coordinated operation of these three subsystems.

4.1 Distribution and supply

Distribution involves construction and maintenance of the physical distribution infrastructure - lines, poles, transformers and substations. Supply involves providing electricity to consumers and collecting money for this. As of now, one organisation called the Distribution Company (DISCOM) manages the distribution infrastructure as well as supply of electricity. Section 4.1.1 describes the operations related to the consumer and related field activities. Section 4.1.2 describes the operations at the head office of the distribution company.

4.1.1 Consumer services

Consumers of electricity include domestic consumers who need power to light their homes, run their fans and other electric appliances, as well as industrial consumers who have to run their factories when the shift begins. They can be commercial consumers like hotels, hospitals, and shops, or agricultural consumers. All types of consumers expect good quality power to be available whenever they need it. The demand for power varies throughout the day, and the power system has to respond to this varying demand. This involves increasing or decreasing generation to maintain load-generation balance, making voltage corrections, ensuring that no line or transformer is overloaded, and in the case of emergencies, stopping power supply to some consumers to ensure that the whole system does not collapse. Information like values of power generation, power flows on lines, voltages at substations and frequency are recorded at regular intervals for further analysis and for payments.

According to the standards of performance of distribution companies, consumers are supposed to be given advance notice (through methods like a press release, information posted on the company’s website, or a message to the consumer’s mobile phone) when there is a planned power cut - say for maintenance or due to power shortage. Whenever the power supply fails with or without such notice being given, the consumer should inform the nearest electricity office. Consumers can also complain at the ‘Fuse Off Call Centres’, centralised complaint centres or using mobile applications. Based on the complaints, and a survey of the area, the problem can be localised and a repair crew sent to solve the problem. With the use of digital maps, linking of consumers to distribution infrastructure, fault location applications and multiple repair crews, these services are going hi-tech, especially in cities. The aim is to minimise the no-power time, since power cuts have an adverse impact on the quality of life and economic activity. In a system that is planned and maintained well, failures are few and of short duration. However, increasing demand and improper and insufficient investments, especially in the distribution system have increased the failure rate, making fault handling a daunting task.

Distribution in a big city or a district may be coordinated from a Distribution Control Centre (DCC). The DCC will have the layout of the substations and feeders in the area and also specifications of various equipment in the distribution system. Information on the current operation status from the substations is conveyed to the DCC so that the staff at the DCC gets a comprehensive view of the operation of the distribution system. This includes ON/OFF status of feeders, power flow on feeders, voltages, frequency values, status of important equipment, etc. This information will be conveyed through sensors at the substation and communication systems like radio or mobile data. The DCC has to watch out for overloading of lines or transformers and take corrective action. It also has to take care of low or high voltages and high phase imbalance. Corrective actions like switching off a feeder or changing a transformer tap (explained in Chapter 3) is usually carried out by a local operator, though in some cases, the DCC can also remotely control the system.

Maintenance coordination and load management are some important functions of the DCC. Maintenance includes routine operations like checking the insulators or circuit breakers, trimming tree branches that may be touching the lines, and emergency responses when there is a break down in the system. Load management includes routine load shedding during power shortage, or providing supply to some consumers only during some time of the day. For example, short duration power cuts are implemented at different times in different areas or agricultural pump sets are given supply in 2-3 batches for 7-10 hours. Emergency load shedding instructions are conveyed from the head office to the DCC, which in turn instructs the field staff to open some feeders to reduce the load.

On the commercial side, the consumer is charged for the electricity consumed. This is measured by energy meters installed at consumer locations. These meters have to be read periodically in order to bill the consumer. This is usually done manually by meter readers, who also check if the meter is working properly, whether it has been tampered or power stolen. Meters are read on a monthly basis and sometimes on a half-yearly basis. At a domestic consumer location, meter reading has just one parameter, which is the cumulative value of the energy consumed. At a factory or shop location, the meter reading can include the energy consumed (active, measured in kWh; reactive, measured in kVARh, or apparent, measured in kVAh), the maximum demand and the power factor. Time of the Day (ToD) metering involves measuring electricity used during different times of the day, since there are different tariffs for different time slots. Peak time use attracts higher charges.

New systems have been introduced in which the meters can be read electronically and remotely. The installation of pre-paid meters is also planned, which can automatically disconnect supply to the consumer if their bill is overdue. After meter readings are collected, electricity bills are issued to consumers. In the case of ‘spot billing’, meter readers issue the bill immediately after reading the meter. Bill collection centres accept payments. These centres also process applications for new connections and requests for replacement of faulty meters.

When there is an electricity accident, the distribution company and electricity inspector are expected to make a report of the accident and study its causes. Based on the regulations on accidents involving humans and animals, the distribution company is expected to pay ex-gratia, which is currently provided for select fatal accidents.

4.1.2 Head office

The head office has to coordinate the day-to-day power purchase to supply electricity to all consumers, monitor the quality of supply and service, and supervise billing and revenue collection. It should also ensure that national programmes on rural electrification, distribution system strengthening, financial bail-outs, energy efficiency and renewable energy are on track. The head office is responsible for preparing regular reports and submitting them to the state government, state regulatory commission and central government. After the E Act, there is an option for big consumers to bypass the DISCOM and directly purchase power from generators, the electricity market or captive generation, as described in Chapter 9. The head office has to approve and keep track of such transactions. The distribution company has to get regulatory approval for power purchase, major capital investment and tariff revision. It is not possible to describe all these functions in detail, but we describe transmission and distribution loss which is an important aspect of the power sector debates as well as financial health of the distribution company, in the next section.

Transmission and Distribution loss

Transmission and Distribution (T&D) loss is an important and by now a familiar index of performance efficiency of a transmission and distribution company. The T&D loss is the loss in active energy occurring between an energy source and consumers over a period of time. The T&D loss is usually expressed as a percentage of the input energy. State Electricity Boards used to have generation, transmission and distribution functions, and T&D loss was a common indicator of efficiency. According to government reports, the average T&D loss for the country was 22% in 2016² Figures for individual states vary from 11-15% (southern states) to 35-50% (states like Bihar, Odisha, and Jammu and Kashmir).

Figure 4.1: Power theft by tapping the power line

Photo credit: photo by McKay Savage on http://flickr.com at https://www.flickr.com/photos/mckaysavage/3921003774

The T&D loss is the difference between the total active energy available (from generating stations and imports) and the total energy supplied to all consumers. There are two reasons why all the energy available does not get recorded as what is supplied to consumers. The first reason is the ‘technical loss’ in the power system, which occurs due to the resistance in power lines, transformers, substation equipment, etc. Technical losses can be calculated using some measurements and the laws of physics. Technical losses can be reduced, but can never be totally avoided.

The second reason is the ‘non-technical loss’ (also called commercial loss), which occurs due to wrong measurements of the active energy supplied to consumers. The reasons for this are theft and faulty metering or billing. Wrong metering of energy sold could be due to a variety of reasons: faulty meters, by-passing of meters, faulty meter reading, wrong estimation of energy consumption of the un-metered consumers (like agriculture), etc. Theft can take many forms: tapping of power directly from the line without any meters, tampering of meters, etc. Figure 4.1 shows an example of tapping low tension lines. In high and extra high tension systems, tapping is not easy, but there are many instances of tampering with the meters, leading to power theft. Since the non-technical loss can never be exactly quantified, it is estimated by the method of elimination. First, find out the total loss by measuring the input and output energy values. Second, calculate the technical loss by simulation studies. Subtract the technical loss from the total loss to get the non-technical loss. If there is overestimation of energy supply to un-metered consumers (agriculture and some poor households), the actual losses are understated.

To understand T&D loss, we refer to Chapter 2 where we have seen that the state power system is made up of three subsystems: generation, transmission and distribution. The constitution of each of the subsystems in a typical state is:

Generation: State owned generation, share from central sector generation, private generation and import from (or export to) other states.

Transmission: Extra High Tension (EHT-132 or 110 kV, 66 kV and above), network of the state transmission company, central transmission company (POWERGRID), and private companies

Distribution: Network of the DISCOMs, 33 kV and below

Figure 4.2: Schematic of energy flows in a state

Source: Prayas (Energy Group)

Figure 4.2 shows the flow of electrical energy from one subsystem to another within a state.³ There are many boundary points between these subsystems. Big consumers are connected to the transmission system at high voltages. A, B, C, D and E are the annual energy flows measured at the boundaries (typically in Million Units). For example, ‘A’ is the total net active energy generation measured at the EHT busbar at the generating station, which is actually part of the transmission system. Internal consumption by auxiliary equipment, loss in the generating station equipment, colony consumption, etc. are subtracted from the gross power generation at the generator terminals to arrive at this figure. Energy flow from export/import happens through the transmission system, and ‘B’ is calculated to get the net import into this system. Consumer supply ‘E’ is the total of metered and estimated values (for un-metered consumers) of energy supply to consumers.

T&D loss is the loss in active energy occurring between an energy source and consumers over a period of time. T&D loss is usually expressed as a percentage of the input energy. Please see Table 4.1 for the formulae to calculate the different loss figures with reference to Figure 4.2.

Table 4.1: Calculation of T&D losses for a state

In most states, transmission and distribution functions are managed by separate companies. There is only one state owned transmission company within the boundaries of a state, but POWERGRID (the transmission company owned by the central government) is present in all states, and some states also have private transmission companies. Loss in the transmission system is the transmission loss and that in the distribution system is the distribution loss. Most states have multiple distribution companies and they are independently evaluated for their performance. The next section covers losses in the distribution system.

Losses in the distribution system

The Distribution Company (DISCOM) incurs energy losses due to technical reasons and revenue losses, because it does not get money for all the energy supplied. Revenue loss happens because of two reasons:

Supplying energy to consumers who pay less than the cost to supply them (they are called subsidised consumers)

Problems in collecting revenue for electricity supplied to consumers

The revenue loss due to subsidised consumers is due to a conscious decision by the DISCOM and the state government, and cannot be avoided. This aspect is not discussed further in this chapter, but covered in Chapter 7. Collection problems occur when consumption is not metered properly or money is not collected, partly collected or not collected on time from consumers. All these factors add up to the revenue loss. Thus, the total loss of the DISCOM is the difference between the total ‘cost of power supply’ and the total ‘revenue collection’. The total cost of power supply is related to the total energy input to the DISCOM (also equal to the total energy purchased by the DISCOM), and the total revenue collection is related to the total energy for which revenue is collected or ‘realised’. This loss includes the distribution loss and the revenue loss and is called the ‘Aggregate Technical & Commercial Loss’ (AT&C loss). Since AT&C loss captures both energy loss and revenue loss, it is used as a parameter for an assessment of the overall efficiency of a DISCOM. The AT&C loss is expressed in percentage terms and the method of calculating it is described below and illustrated in Figure 4.3.

The AT&C loss can be calculated by using financial figures or energy figures. We describe a simplified methodology using energy numbers.⁴ We begin by introducing a few terms:

Energy Input is the energy input to the DISCOM.

Energy Billed (in units) is the energy for which bills are issued (using meter reading or estimation).

Amount Billed (in rupees) is the total of all bills in rupees.

Average Billing Rate (ABR) is the ratio of Amount Billed to Energy Billed. It is measured in Rs / Unit and indicates the average price of electricity for all the consumers of a DISCOM.

Thus, ABR = Amount Billed / Energy Billed

Billing Efficiency is the ratio of Energy Billed to the Energy Input. It is measured as a percentage and is a measure of the efficiency of the metering and billing system.

Thus, Billing Efficiency = Energy Billed / Energy Input

Collection Efficiency is the ratio of revenue collected from consumers (measured in rupees) to the billed amount (measured in rupees). Collection is also called ‘Realisation’ and includes the subsidy received from the state government to support some consumers. In our calculations, we assume that all the required subsidy is paid. The Collection Efficiency is measured in percentage and 100% indicates that all the money for supplying electricity is collected from all consumers and the state government. But it is mostly less than 100% due to disputes or delays in payment.

Thus, Collection Efficiency = Revenue Collected / Amount Billed

Energy Realised (measured in units) is the energy billed for which a collection is made or ‘realised’.

Thus, Energy Realised = Energy Billed x Collection Efficiency

AT&C Loss = (Energy Input - Energy Realised) / Energy Input

The AT&C loss can also be calculated using Billing Efficiency and Collection Efficiency, by proper substitution using the formulae given before.

Thus, AT&C Loss = 1- Billing Efficiency x Collection Efficiency

Figure 4.3: AT&C loss calculation for a DISCOM

Source: Prayas (Energy Group)

See Figure 4.3 giving illustrative figures to understand the AT&C loss in a distribution company. In this example, out of the 100 units of energy input to the distribution network, 10 are lost as technical loss and 5 as non-technical loss. This results in a total distribution loss of 15%. The remaining 85 units are supplied and billed to consumers at an average rate of Rs 4/unit (ABR is Rs 4/Unit, billing efficiency is 85%). Against Rs 340 that should be collected from them, Rs 272 is collected, resulting in a collection efficiency of 80% (collection loss is 20%). The AT&C loss is the difference between energy input (100) and energy for which money is collected (68). It is expressed as a percentage of energy input and is 32%.

The AT&C loss figures for distribution companies are higher than the corresponding distribution loss figures since losses due to non-realisation are also included. The AT&C loss figure varies from 10-15% (DISCOMs in Andhra Pradesh, Gujarat, Karnataka) to more than 30% (DISCOMs in Bihar, Jharkhand, Odisha, Haryana, Jammu and Kashmir).

Arrears will build up if consumers do not pay. Arrears from consumers for all the state owned DISCOMs in the country totalled nearly Rs 1,15,000 crores in 2016⁵, which is around 30% of the total revenue. The quantum of arrears varies across states and is as high as 40% in some states.

To conclude: we note that revenue losses occur due to 1) the energy loss due to technical and non-technical causes, and 2) the revenue loss due to collection inefficiency. Reduction of non-technical losses and collection efficiency requires management measures like prevention of theft, repair of meters, audit of billing, efficient revenue collection, etc. These measures involve many socio-political challenges and can succeed only if distribution companies have the political will and consumers extend cooperation. A reduction in technical loss requires capital expenditure on distribution system improvement. This could include installing appropriate conductors, increasing the capacity of transformers and installing capacitors. There is also the need for proper maintenance of lines, transformers, insulators and joints.

AT&C loss trends

The transmission loss is quite low at around 4%, while the AT&C loss varies from 10 to 50% across the country. Some DISCOMs in southern and western states report very low AT&C loss of the order of 10-15%. Even within DISCOMs, there is a wide variation of AT&C losses across districts or towns. The target of the central government’s Ujwal DISCOM Assurance Yojana (UDAY) programme is to bring down the AT&C loss in the country to 15% by 2019, which is a tough challenge. Table 4.2 is a summary of the typical figures of different efficiency indicators and desirable benchmarks for transmission and distribution (rows starting from metering efficiency apply only to DISCOMs). These are approximate numbers compiled from various sources. There has been substantial improvement in the last decade, but it is not uniform across all states, and there is scope for further improvement.

Table 4.2: Typical Transmission and Distribution efficiency indicators

There has been improvement in the efficiency parameters in the past few decades. But since most agriculture and many domestic consumers are not metered, their consumption is estimated, thus raising questions on the accuracy of these numbers. Metering all consumers is a big challenge, but as far as possible all consumers should be metered and all 11 kV feeders and distribution transformers should have the automatic meter reading (AMR) facility. This data should be publicly available for anyone to cross check. The metering and billing system should be audited by third party agencies on a periodic basis. To reduce theft, management measures (like taking consumers into confidence, and ensuring timely punishment for theft or non-payment of bills) are equally or more important than technical measures (like computerised billing, insulated cables, locating meters on poles, or high voltage distribution system). This is because technical measures are costlier and resourceful people may find ways to bypass them.

4.2 Transmission system

At the state level, the minute-to-minute operation of the power system is coordinated from the State Load Dispatch Centre (SLDC), typically located in the state capital. The LDC has communication links to three or four Sub Load Dispatch Centres (Sub-LDCs), which in turn are linked to major transmission substations, generating stations and distribution control centres.

Thus, the LDC gets information about major generating stations, transmission substations and the distribution system on a continuous basis. Information on the generating station includes ON/OFF status of generating units, the power generation level, frequency, voltage, reservoir level (for hydro stations), coal availability (for coal stations) and any other major station information. Substation information includes status of transmission lines which emanate from here (ON/OFF status, power flow, voltage) and the status of the substation (voltage, frequency, and status of major equipment like transformers). The LDC also receives information regarding weather conditions from different locations in the state. The LDC can communicate instructions to the generating station or transmission substation.

The state LDC has two-way communication with the Regional LDC (RLDC). The RLDC monitors a whole region. For example, the Southern Regional LDC located at Bangalore monitors Andhra Pradesh, Telangana, Tamil Nadu, Karnataka, Kerala and Puducherry. The RLDC also gets information from the generating stations and substations of the central utilities (like NTPC, NPC, POWERGRID etc) and multi-state generating stations (generating stations which share power with multiple states). The LDC (at the state as well as the regional level) has communication links with all these locations using reliable communication media that can carry information and voice. The five RLDCs (North, East, West, South and North East) have reliable communication links to the National Load Dispatch Centre (NLDC). See Figure 4.4 showing the five electricity regions in the country and Figure 4.5 showing the grid operational hierarchy.

Figure 4.4: Electricity regions in India

Figure 4.5: Grid operational hierarchy

Source: Prayas (Energy Group)

The five regions shown in Figure 4.4 are electrically interconnected now, even though each state and region conduct their planning of operation independently, though in coordination with others. Figure 4.5 shows the NLDC (located at New Delhi), Backup NLDC (located at Kolkata), five RLDCs, SLDCs and Sub-LDCs. All generating stations, except the central and multi-state ones are linked to the SLDC. Central and multi-state stations are connected to the RLDC. Typically, the LDC prepares a generation schedule for each 15-minute block in the day (total of 96 schedules) for each generating station as well as a demand drawal schedule for the DISCOMs one day in advance. The demand forecast, weather information, maintenance schedule (prepared for the year in advance or prepared when there is some equipment failure), relative power generating cost, contractual agreements, water/fuel availability, irrigation requirements, and any limitations on power carrying capacity of transmission lines are used by the LDC to prepare the generation schedule.

Many organisations are involved in planning and operation of the transmission system. Table 4.3 summarises the names and brief details of these organisations.

Table 4.3: Organisations involved in transmission system

Under normal conditions, the generating stations are ‘dispatched’ (generation levels decided) as per the ‘Merit Order’. The merit order for the generating stations in a state is prepared based on the variable or marginal cost of the station and some other considerations (see Box 4.1 What is Merit Order?). The station which is on top of the merit order (the cheapest) is dispatched first, the next one after that, and so on.

Box 4.1: What is Merit Order?

There are many generating stations in a state, based on different fuels and technology. Some will be old while some are new. A ‘Merit Order’ of these stations is a way of ranking the stations based on the ascending order of variable cost (or marginal cost, which is the cost required to generate one additional unit). Stations at the top of the merit order are loaded (dispatched) first, followed by the next, and so on, to reduce cost. This is called Merit Order Dispatch (MOD). There are some stations which are considered ‘must run’, which means that they have to be dispatched if they are operational. These include the renewable energy stations and nuclear stations. Dispatch of hydroelectric stations often depends on water availability, irrigation requirements and needs for sudden changes in power generation. Hence merit order largely is relevant for coal and gas based stations.

As we shall see in Chapter 6, the power generation cost consists of two components. The fixed cost is independent of the generation level, since it is related to capital investment and some costs which have to be paid independent of the amount of power generated. The variable cost depends on the generation level, since it is related to fuel cost. For hydro and renewable stations, the variable cost is near zero, and what is usually mentioned as variable cost is actually an average cost/unit of power generation based on the fixed cost. The merit order is prepared based on the variable cost (Rs/Unit) for the station, which typically includes mainly the fuel cost component. The merit order is prepared once a month or once a year. Cheapest coal stations top the merit order, followed by other coal stations, gas based stations, and diesel stations. From 2017, central government has been providing the merit order of all generating stations in the country on a portal http://meritindia.in.

A typical merit order for select stations in Andhra Pradesh state is given in Table 4.4. For the sake of completeness, we have included some renewable and nuclear stations, in addition to gas and coal based stations. For interstate generating stations (which sell power to multiple states), the capacity allocated to AP is indicated. Renewable, hydro and nuclear stations are dispatched irrespective of variable cost, but the thermal (coal and gas) stations are dispatched based on merit order. The variable cost is high for coal plants which need long distance coal transportation or are less efficient, assuming similar coal costs across plants. The costlier plants will be dispatched for less time and hence will have a lower Plant Load Factor (PLF).

Table 4.4: Merit order for select stations in Andhra Pradesh

Notes: Cost of generating one unit from hydro and renewable stations (also called tariff) is not the marginal cost of generating one additional unit or fuel cost, but figures decided based on fixed cost investment, spread over the life of the station.

Source: Adapted from the Government of India website on merit order, http://meritindia.in/state-data/andhra-pradesh, Andhra Pradesh data accessed on December 21, 2018.

This schedule is made available to the LDC, which conveys the dispatch instruction to the generating station, and the operating staff at the station ensures that it is followed.

The generation dispatch schedule based on the merit order is followed until some unforeseen event occurs. This could be a sudden increase or decrease in load (as against what was forecast), a failure of a generating station or transformer, or opening up of some transmission lines. These events can cause overloading, voltage deviations and frequency deviations. Hence transmission lines and substations are continuously monitored to sense any overloads or abnormal voltages. Since the LDC has all the information of the whole system, corrective action to handle any unforeseen event is decided here. The LDC then issues instructions to the generating stations and substations to take corrective action. What are these actions? If the generation is not sufficient to meet the load (which is indicated by low frequency, as we will see later in this chapter) or if some lines are overloaded or if voltages are abnormally low, load shedding instructions are issued by the LDC to substations. If the frequency drops very quickly to a very low value, LDC can issue instructions to start services of ancillary services, which can provide additional generation for a short duration. If that does not stabilise the frequency, the under-frequency relays located at substations are expected to act to shed loads automatically.

Usually the load shedding requirements are known in advance. For example, in most states agriculture pump sets are supplied for only 8-10 hours during specified daily time periods. As we will see in Chapter 8, planning studies provide load forecast and possible generation levels. Load shedding is to be planned if generation is not sufficient to meet the load. The LDC issues these scheduled load-shedding instructions to substations.

The LDC also coordinates repair work as well as planned maintenance of transmission lines and generating stations. Whenever such repair work is to be undertaken, the LDC issues a ‘Line Clear’ instruction, which indicates that the line or generator is not to be put on service during the repair time. The LDC has to plan the Line Clear time to ensure that normal system operation is not hampered. Some typical examples of maintenance and repair work are cutting tree branches which are too close to the power line, periodic cleaning of the EHT line insulators (which gather dust and pose a risk of electrical arcs and insulation failures, also called flashover), periodic checks of transformers, generating units, etc. In some cases, work can also be carried out when the line is in service and power is flowing on it. This is called ‘hot line maintenance’ and requires special equipment. But when hot line maintenance is not possible, the equipment has to be isolated from the power supply till the repair work is completed and tests for proper functioning carried out.

After the introduction of power markets, bulk consumers (like factories or DISCOMs) can buy power from the generator of their choice. This can be done through bilateral contracts between buyer and seller or through power exchanges. These will be described later in Chapter 9. In any case, the transmission grid has to be used to transfer this power. Contracts are finalised only after the LDC checks if such power flows will result in any overloads. Even after contract finalisation, such transactions are allowed only after the LDC clears it periodically, based on operating conditions.

The SLDC keeps a record of all the information gathered. This is used to analyse the system performance and is a major input to the planning department. The planning department uses this information to prepare load forecasts, assess power losses, give suggestions to reduce losses, plan for increase in transmission or generation capacity, improve mechanisms to avoid grid failure, etc.⁶ The SLDC also passes on important information to the regional load dispatch centre (RLDC) and to any other government department as required. The RLDC in turn prepares reports, conducts analysis studies and passes important information to the NLDC.

The SLDCs and RLDCs also provide information to the Regional Power Committees (consisting of all major generators and transmission companies in the region, and the CEA) and the National Power Committee (consisting of representatives from all Regional Power Committees, the NLDC and the CEA). This includes key operating parameters like frequency and voltage, finalised generation and demand schedules, actual generation and withdrawals, as well as deviations from schedule. Data from LDCs are used by Power Committees to decide the penalties for deviation from schedule, based on the Deviation Settlement Mechanism regulations of the regulatory commission.

In many ways, the LDCs are the nerve centres which coordinates the power system operation. In spite of all this coordination, sometimes the system does not recover from a breakdown that has occurred in some part of the grid. Things go from bad to worse and end up in a blackout of a whole state or region. This is called a grid collapse during which a whole state or region has no power for hours. See Box 4.4 Grid Collapse, blackout and brownout later in this chapter.

4.3 A quick tour of generating stations

The components of a generating station have been explained in Chapter 3. Let us take a tour of some generating stations to understand their operation.

4.3.1 Coal station

Let us start at the coal yard. A 2130 MW coal based station (with three units of 210 MW capacity and three units of 500 MW) burns about 1200 tons of coal per hour. This can easily be ten train loads of coal per day.⁷ The coal yard is designed to hold coal stock sufficient for a few weeks and there will be an alarm if the amount of coal is sufficient for just a day or two. This can happen due to problems in coal production or transport. Hence, a strict vigil is maintained on supply chain and stocks so that one does not suddenly run out of coal. The health of the equipment that crushes the coal and transports it to the boiler has to be monitored. Emergency and preventive maintenance has to be carried out. The station also needs a lot of fresh water, mainly for cooling, to the tune of around 80 lakh litres/day, which is equal to what is consumed by nearly 1 lakh people per day.⁸

Associated with the boiler, turbine, generator, control unit and switchyard are hundreds of devices like motors, pumps, switches, and valves. The settings and operation of all these devices have to be maintained continuously. Temperature and pressure of the steam has to be maintained within limits. Typical steam pressure is 100-150 atmosphere (typical pressure inside a pressure cooker is 2 atmosphere) and temperature is 500-600 degrees centigrade. Turbine health has to be monitored on a continuous basis by looking at several parameters. For a 210 MW generating unit, around 5000 parameters must be kept track of to ensure smooth operation. Coordinated operation of the station is done from the control centre (See Figure 4.6). The critical parameters are made available to the operators at the control centre who are able to operate the equipment remotely.

Figure 4.6 Generation station control centre

Photo credit: from Gujarat Industries Power Company Ltd. (GIPCL) website at http://www.gipcl.com/writereaddata/Portal/Images/Energy-Efficiency2.jpg

The coal based station is ideally suited to run at full capacity all the time. But due to variations in load, shortage of peaking plants and variations in renewable power generation, the coal plants also have to be ready to reduce generation when the net demand (net demand is equal to the total demand minus must run renewable power generation) is low.⁹ Such instructions are issued by the load dispatch centre. All systems in the plant have to make the necessary adjustments to suit the generation level. Some parts of the coal based plant like the boilers require time to respond to commands on generation level changes, since temperature changes need to be brought about gradually. It could take a few minutes for such commands to take effect and are issued only when essential.

All these actions are coordinated from the plant control centre. The control centre also monitors the health of different equipment in the generating station. In the case of any unforeseen failure of any equipment, the first step is to start the backup systems so that generation is not affected. The next stage is to initiate repair of the equipment. The control centre also maintains a record of parameters like the generation level, coal usage and equipment health. Periodic maintenance of each plant is decided at the utility head office. This is typically once a year and is called ‘Planned Outage’. But sometimes unforeseen problems occur. For instance, some critical component might fail, or there could be a fire or a water tube leak. In such circumstances, an emergency shutdown is necessary for repair, which is called ‘Forced Outage’. The staff is trained to minimise the number of such failures and the duration of the failures when they occur.

4.3.2 Hydro station

A hydro station is also made of many generating units, for example, say 6 units of 110 MW each. Hydroelectric units are the most flexible in terms of fast changes in generation level. The number of components is less compared to a thermal station. The load dispatch centre can ask the station control centre to change the generation level at short notice. Some hydro stations have ‘black start capability’ which is the capability to start generating power when there is no power supply in the grid. This is very useful during restoration of supply after a major grid failure.

The control room has to keep track of the reservoir levels and ensure full generation when the reservoir is overflowing, and bare minimum generation when the level is low. Many hydro plants have a reservoir formed by the dam, and the stored water is also used for irrigation. In several dams, the priority is given to irrigation and the plant control has to follow orders based on irrigation needs or minimum environment or ecological flows (needed to maintain the river eco-system). In such cases, the power generation is only incidental. There are run-of-the-river hydro plants with no or very little storage which generate power when there is water flow in the river.

4.3.3 Natural Gas based station

Compared to the coal-based station, a natural gas station is much easier to handle. There is less maintenance and start-up and shutdown are faster and easier. Open cycle plants have only gas turbines whereas combined cycle plants (CCGT) have gas turbines as well as a steam turbine. CCGT plants cannot be completely shut down and restarted quickly because the steam turbine takes time to start up or shut down. These plants are connected to the source of gas by pipelines or located near ports where gas arrives in ships. Gas is not usually stored in very large quantities at the station due to safety reasons. Care has to be taken in handling and storage of fuel.

These stations are usually required to change generation levels at short notice by the LDC. The station control centre which receives these instructions initiates required actions. The control centre also keeps a record of all parameters and coordinates emergency or planned repair.

4.3.4 Wind and solar

A wind-based power plant usually consists of many wind turbines spread over a large area. These turbines are usually induction generators which generate power at the grid frequency and hence are directly connected to the grid. There are inbuilt protection systems to prevent damage when there is high wind or large variations in voltage or frequency. Solar plants also consist of many panels generating DC power. They are electrically connected to each other and to the grid through an inverter.

Wind and solar generators require lesser maintenance in general as compared to the conventional generation plants. Operation of wind and solar plants consists of activities like recording information about generation, routine checks and cleaning the solar panels. These plants are expected to provide forecasts of generation based on expected weather conditions. If there is no storage, all the power generated by these plants is fed into the grid. Therefore, these forecasts help the grid operators to plan generation by other power plants.

4.4 The frequency and voltage matching game

Frequency and voltage are the most important health indicators of a power system. Frequency is the same at all locations in an interconnected system, whereas voltage can slightly vary across locations. In a power system, there is a close correlation between active power (MW) and frequency. Whenever active power generation is not sufficient to meet the active power load, the frequency starts dropping and vice versa. Similarly, there is a correlation between the reactive power (MVAR) and voltage. When the reactive power generation is more than the reactive load, the voltage is higher than the required levels, and vice versa. Control of active power and reactive power thus ensures correct frequency and voltage levels in the power system. To a large extent, these two correlations can be looked at independently. The Indian Electricity Grid Code (IEGC) prepared by the Central Electricity Regulator Commission and State Electricity Grid Codes (SEGCs) prepared by State Electricity Regulatory Commission specify the roles and responsibilities of power generators, transmission companies, distribution companies and bulk consumers towards maintaining grid discipline to ensure proper frequency and voltage at all times.

4.4.1 Frequency and active power

The daily load curve was discussed in Chapter 3. It gives a plot of hourly MW (active power load) for each hour. It can be seen that the change of load from one hour to the next is much less during off-peak hours (afternoon, middle of the night). During peak hours the change can be quite high (a few thousand MW). The load dispatcher prepares an hourly generation dispatch schedule to meet the load forecast and issues instructions to the generating stations.

Since all the power generated by renewable sources has to be purchased by the distribution company, usually a net load curve is prepared, after subtracting the expected renewable generation. But there are uncertainties in the actual load and generation, especially from renewable sources. Control mechanisms are put in place to handle these variations. Every conventional generating unit has a piece of equipment called the speed governor. It senses the rotation speed of the generator and based on this speed, changes the input into the turbine. The input could be steam in the case of coal, water flow in the case of hydro, and so on. The load could be slightly more or less than what was forecast. When the load is more than generation, it acts like a brake on the rotating shaft of the generator and the generator slows down, bringing the frequency down. Speed governors installed on the generator sense the slowing down of speed and increase the input to the generator turbine (steam or water flow) so that additional power is generated and the speed is not reduced further.

In practice, there are many generators in a power system. Since they are all connected, they all need to operate at the same frequency. To understand this, consider that all generators are connected to a single shaft (which is a little flexible), and therefore they all turn at the same speed (like a tandem cycle). When the load is more than generation, all generators first slow down. By the action of the speed governor, generators make their own contribution to this additional power requirement to bring in a new balance of load and generation. This balance is achieved at a lower speed and therefore lower system frequency.¹⁰ This operation of immediately reacting to a change in load is ‘Free Governor Mode of Operation’ (FGMO, as it is currently called in the regulations, but the national load dispatcher has suggested to change the terminology to ‘Primary frequency control with droop’) and typically happens within a few seconds of load change.¹¹ The next step is to bring the system frequency back to the nominal value, that is, to bring the speeds of the generators back to the old value while producing the same power. Another corrective action called Automatic Generation Control (AGC) is needed for this purpose. The AGC sends signals to the speed governors of each generator in the system. This is to increase the speed of rotation, while ensuring that the generation equals load and the system frequency is quickly brought back to the nominal value.¹² This process may take a few seconds to minutes to complete. The LDC is expected to calculate the AGC commands of the different generating stations and issue them. All these steps happen in reverse when the load is less than generation. The frequency increases first and the control mechanism brings it back to the nominal value after a while.

This frequency control feature is implemented at the generator level. The AGC is implemented at the system level, which is regional level in India at present, but which will soon be at the national level. These operations ensure that the system works at the nominal frequency. Operation of the system at very high or low frequency and frequent variation of the frequency is harmful for the generating units and motors. For the generator, efficiency and life will reduce. There are similar issues with motors, and their speed change will have impact on the function they are doing - like pumping or blowing air. Even today, many generating units do not have free governor operation and AGC is not implemented in India but a pilot implementation is underway. The gradual tightening of the allowable frequency variation band is helping to reduce variations in frequency.

It is however clear that maintaining the frequency-active power balance is largely in the hands of the power utility. This is not the case with the voltage-reactive power balance, where the consumer also has an important role to play, especially in the distribution system. We cover this aspect in the next section.

4.4.2 Voltage and reactive power

We have looked at Ohm’s law in Chapter 2. Whenever current flows through a line, which has resistance, voltage will reduce. Therefore, it is common to see low voltages at consumer locations, far away from the transformer or generating station. In a DC system, the only solution to this problem is to locate generating stations all over the state. This is not a practical or economically viable idea. In an AC system, in addition to this, there are a few other tricks to maintain voltage. We will see later that all these tricks are related to the proper management of reactive power flows.

One trick is to locate Extra High Voltage (EHV) substations close to load centres throughout the state. We have seen that voltages can be easily increased or decreased in AC. Generating stations may be located far away from load centres, in hills or near coal mines. Power generated there can be stepped to EHV and transmitted over long distances to the load centres. This brings the generating station ‘electrically’ close to the load centre and is equivalent to physically locating the generating station closer to the load centre. This helps to improve the voltage at substations, which are far away from the generating station. Pockets of low voltage in regions have been removed by locating substations in such regions.

Another way of managing low voltage is to make a minor adjustment to the transformers located at the substations. Transformers have two coils - one at the input side and another at the output side. The voltage transformation ratio in a transformer depends on the ratio of turns in these coils. Thus, in a transformer that converts 33 kV to 11 kV, typically seen at the distribution substations, the ratio of turns will be 33: 11 = 3:1. When the input voltage is 33 kV, this transformer will give 11 kV output. If the output voltage reduces to say 10 kV (that is by 10%), it would mean that the input voltage is 30 kV. In order to get 11 kV voltage output, the turns ratio should be changed to 30:11 = 2.73:1. This is done by ‘Tap Changers’ present on some transformers, which can correct voltage variation of a few percentages. Many voltage stabilisers also employ the same principle.

Another trick is to locate reactive power generators at different points in the power system. These could be power generators, capacitors or Static VAR Compensators (SVCs), all of which can generate reactive power as needed. Reactive power consumption reduces the voltage and production increases the voltage. Reactive power is not present in DC systems, whereas in AC, reactive power control can be used to manage voltage. Balancing consumers and producers of reactive power right at the planning stage is the first step. Motors that consume reactive power constitute the major load in a power system. Therefore, in power system terms, balancing means locating capacitors (reactive power producers) close to the motors. Thus agricultural pump sets, factories and substations have capacitors installed. Some generators can also produce reactive power. This production can be adjusted during actual operation to improve voltage. To understand this further, look at the tandem cycle analogy in Box 4.3 Ride a cycle to learn how the power system works.

AC power systems employ all these tricks to increase voltage levels at substations far from the generators. But sometimes a new problem crops up: the voltage becomes too high, especially at low load periods. Reversing some of these tricks helps to solve this problem. Both utilities and consumers have a role to play in maintaining a good voltage in the system. The utility can do this by planning and operating devices at generating stations and substations, and the consumer by installing required capacitors or voltage stabilisers.

4.4.3 The importance of coordinated operation

The previous two sections described two important correlations in the power system: active power and frequency, and reactive power and voltage. Frequency is the same at all interconnected points in the system, whereas voltage can vary. Both should be maintained within limits. Coordinated planning and operation of the power system is essential to ensure this. Box 4.3 Ride a cycle to learn how the power system works explains this coordinated operation.

Box 4.2: Ride a cycle to learn how the power system works

To understand how the power system works in a co-ordinated fashion, we are using an analogy initially suggested by Lennart Soder and developed by others.¹³ Consider a long, tandem cycle with many seats for cyclists, many pedals with corresponding sprockets and a long, slightly elastic chain connecting all of them. The cycle itself is made of slightly elastic material so that it takes some pushes and pulls in its stride. The cycle runs on a straight road and the aim is to keep it moving at the same speed and keep it upright all the time, as shown in Figure 4.7.

Figure 4.7: The tandem cycle to explain coordinated grid operation

Generators are those cyclists who pedal. Some are big and strong, some thin and weak. Depending on their capacity and instructions given to them, they contribute some share of energy to the cycle. There is a leader who keeps track of the speed and if it is low (say while climbing a slope), he shouts out to some generators to put in more effort. If the speed is high, the leader asks some of them to take it easy. Thus, there are excursions of speed (which is equivalent to frequency in a power system), but by and large, it is kept constant.

There are some cyclists whose legs are strapped to the pedal. They do not put in any effort to turn the pedal, but put in effort to stop it, while their leg continues to turn with the pedal. They contribute to a slowing down of the cycle and are like motor loads in the power system. There are some cyclists whose feet do not rest on the pedal at all, but they have a hand-brake, which they keep pressing. They are like the resistive loads. Sometimes, when the speed is too low (say when some generators are tired or when climbing a hill), and the leader is not able to bring the speed back to normal by shouting out to the generators, he asks some of these loads to help, by easing the resistance to pedal or releasing the brake. This helps to bring the speed back to normal. This is like load shedding.

The slightly elastic chain that connects all the sprockets is like the transmission network which connects all generators and loads. The connecting chain ensures that all the sprockets turn at the same speed. The upper portion of the chain has a constant tension (which is like phase voltage), and the lower portion is without tension (which is like neutral).

Most of the seats are arranged in a straight line in the middle of the tandem cycle. A few seats are arranged a little to the left and a few a little to the right of this line. A few seats are adjustable, and can be moved a little to the right or left as needed. It is clear that cyclists off the centre line - be they rightists or leftists - tend to make the cycle go off-balance. If the right-siders and left-siders are balanced, the cycle remains steady and upright. The upright position of the cycle is like having a good voltage profile and a good balance of reactive power. Right-siders are like motors that consume reactive power, and left-siders like capacitors that produce it. Adjustable seat riders are like some generators or variable reactors that can either consume or produce reactive power. It is the job of the leader to ensure that right at the beginning there is balance of right and left-siders. If there is a left-sider, he locates a right-sider close by and vice-versa. When the cycle is in motion, he issues necessary instructions to see that balance is maintained. This could be asking an adjustable seat rider to move or making some right-siders get off the cycle.

Thus coasts the tandem cycle - always on the move, always stable, under the watchful eyes of the leader. If the leader is not able to coordinate the cycle operation, the cycle and all the riders fall down, which is like a grid collapse. A grid collapse happens when many transmission lines open and generators stop supplying power. A wide area loses power supply, which is called a blackout. When large areas experience low voltages, it is called a brownout.

Many would remember the two massive Indian grid collapses in July 2012. The first one on 30th July led to a power blackout of an area with around 30 crore people. The second and bigger one on 31st July affected a bigger area with 62 crore people, nearly half the Indian population, spread over the north, east and north-eastern regions. This outage is considered the biggest in the world so far, in terms of the number of people affected. It took hours to restore power supply to all areas. After an enquiry, many steps have been taken to prevent a recurrence of such events.¹⁴ These steps include third party audits of protection systems, increasing the power of load dispatch centres to coordinate grid operation, tightening the rules about generation or power withdrawal from the grid and setting up a National Reliability Council.
Box 4.4 Grid collapse, blackout and brownout provides an overview of grid collapse.

Box 4.3: Grid collapse, blackout and brownout

Two massive grid collapses happened in India in 2012 - on 30th and 31st July. The first one took more than 13 hours to restore, while the second was restored in more than 8 hours. On January 2, 2001, all the northern states of India went dark in the early morning hours. September 11, 2001 was the day of attacks on the World Trade Centre in the USA and also the day when power supply was disrupted in the entire southern region in India at 1300 hrs. Starting from the opening up of a transmission line, there were a series of trips and all the southern states had no power. It was the turn of the Western grid on July 30, 2002, when it collapsed at 20:11 hours. In all these cases, there were blackouts lasting for many hours. Lights went out, trains were stranded, factories came to a grinding halt, and production losses amounted to thousands of crores of rupees.

Transmission grid and grid collapse have been covered in Chapter 3. In normal circumstances, the interconnected network of transmission lines and generating stations are in a state of dynamic balance - like a circus artist walking on a tightrope holding a long pole for balance. Whenever there is a disturbance, an expert circus artist regains balance after some swings of the stick. If the disturbance is big, or the artist is not experienced, there will be wild swings of the balancing stick and down he will fall to the net below!

Disturbances happen in the power system too. These are in the form of sudden openings of transmission lines, tripping of generating units, sudden changes in load, fall in voltage, etc. Very often, the power system manages to regain its balance after such events. But sometimes, one event leads to another (which could be another generator or transmission line tripping) and a set of cascading events causes the grid to collapse. Most of the generators trip and many transmission lines open resulting in a whole state or many states losing power for long periods. This is typically called a blackout. It may take only a few minutes from the first trigger for the collapse.

The opening up of a 230 kV line due to wrong relay settings triggered the famous ‘Great blackout’ in the US on November 9, 1965. At 17:16:11 hrs the line opened up, leading to a series of events, and after about 10 minutes, from 17:27:00 hrs, for about 13 hours, New York and the surrounding areas had no power. This blackout triggered many mechanisms to prevent such future occurrences, including the setting up of the Northeast Power Coordinating Council (NPCC) in 1966, and the North American Electricity Reliability Council (NERC) in 1968. Despite these measures, a series of lightning strikes caused tripping of transmission lines and triggered another blackout in New York on July 11, 1977. This one took 25 hours to set right. Another massive blackout in the eastern US and Canada took place on August 14, 2003. It is reported that about 61,800 MW of load was lost and nearly 50 million people spread over 240,000 square km were affected for 15-24 hours. There have been many large blackouts in different parts of the world including Europe, China and Australia during the last two decades (1999-2016).¹⁵

These blackouts have raised many fundamental questions on the operation and planning practices after power sector reforms. The traditional priority order of grid operation has been to ensure security or reliability of supply first, followed by ensuring quality of supply (frequency and voltage) and finally optimise economy (in cost of generation and operation). There are questions if this priority order is being changed to give more importance to economy, at the cost of reliability or quality. Having many players in the sector, some of them acting only to protect their short-term economic interests, also makes it difficult to maintain reliability and quality in the post-reform era.

In Chapter 3, a grid of generating stations and substations interconnected by transmission lines was compared to a tent supported by poles and ropes. This is shown in Figure 4.8. The bamboo poles represent generators, the ropes tethering the tent to the ground are like loads, and the criss-crossing ropes of the net of the tent are the transmission lines. If a weight falls on the net or a few bamboo poles or ropes break, or a spike comes off the ground, there will be a little swing, after which the tent may adjust to a new position of equilibrium. It is also possible that timely intervention by a few workers may prevent further damage. But if many weights fall or many poles or ropes break at the same time, it may set off a chain reaction leading to a collapse of the tent. Once the tent flops down to the ground with many broken ropes, spikes and poles, it is very difficult to put it back up. This is similar to a grid collapse when many transmission lines open, loads lose supply and many generators trip. It takes hours to bring things back to normal.

Figure 4.8: Grid collapse

Source: Prayas (Energy Group)

There are many reasons why it takes a long time to restore a collapsed power system. In such a system, all generators would be OFF and most transmission lines OPEN. Generators need some external power to start up. Only a few stations have their own source of start-up power in the form of small generator sets. This capability is called black-start capability. After a collapse, these stations are started up first. Power may also be borrowed from a neighbouring utility to start up some generating stations. After a few generators start up, transmission lines are closed one by one, connecting load to the system. Some precautions have to be taken when connecting the generators and the transmission lines to the grid. It must be ensured that voltage, phase and frequency are equal before the final instruction to close the circuit breaker is given. This procedure is called ‘synchronisation’. One by one, generators and transmission lines have to be synchronised to the grid. The LDC has to ensure that the load generation balance is maintained throughout. No wonder bringing the whole system back to normal takes several hours.

Sudden swings in frequency or voltage are indications that the LDC receives of a possible grid collapse. Immediate actions like load shedding, changing generation levels, reducing voltage levels (to reduce load), help to save the situation. A ‘brown out’ is the reduction of voltage in some areas, which helps to reduce the system load. Lights will dim and motors will turn slower when this happens.

4.5 What is new?

There are many ongoing changes in the Indian power sector, which introduce new dimensions of power system operation. Chapter 10 also covers these changes, but here we provide some aspects related to operation.

After many initiatives to electrify villages, finally all villages in India are now connected to the electricity grid and more than 95% households have been provided connections as of April 2018. The next challenge for distribution companies is to provide sufficient, affordable and quality electricity to all consumers. After many years, many states have a higher generation capacity than the demand. But even today, small consumers face many power outages and long delays in restoring power supply. These are mainly due to operation and maintenance issues with the distribution system. Efforts to address these challenges include strengthening the distribution network, mobile applications to record complaints, automatic meter reading, pre-paid metering (similar to pre-paid mobile connections) and smart meters. A scheme for Direct Benefit Transfer for subsidising electricity supply to needy consumers has also been proposed. It remains to be seen how these measures would address the challenges.

With advancement in technology and reduced prices of renewable energy, there has been some increase in energy from these sources at consumer locations, the main option of which is systems based on solar roof top. Thus a consumer also becomes a producer of power, and is called a ‘prosumer’. These systems are connected to the grid and when the generation is more than demand, excess power is ‘banked’ with the grid. With reduction of battery storage costs, there is also the option of having solar systems coupled with batteries which can store the excess and discharge when needed. For remote locations, solar with storage facility can be set up as a stand-alone system not connected to the grid. Since solar generation is DC and most domestic appliances can work on DC, there is a plan to have Low Voltage DC (LVDC) networks for homes or small communities. Electric vehicles are being encouraged and infrastructure for charging is being set up. Batteries in these vehicles can also act as distributed storage. Smart meters can facilitate controlling electricity demand at homes (say by switching off an air conditioner when the system demand is high) or drawing power from distributed battery storage.

After the 2012 grid collapse, many steps have been initiated to prevent such events and improve the ‘resilience’ of the grid, i.e. make it less prone to failure. These include technologies like wide area phase angle measuring and ensuring adequate reserves in generation and transmission. Ancillary services (grid support services) like peak power, reactive power and black start capacity are being developed on commercial principles. Steps are also being taken to provide more powers to load dispatch centres and improve the planning process.

Endnotes

1 This description is adapted from the first chapter of the classic book Electric energy systems theory: An introduction by OI Elgerd.

² This figure and the T&D loss figures for different states are from the All India Electricity Statistics published by CEA in 2017. According to the International Energy Agency (IEA), the world average for T&D loss was 8%, and the figures are less than 10% for China, the US, and Europe.

³ This is a simplified version. There are many details which are not considered. For example: loss in export/import lines, energy inputs from captive power stations at consumer locations, multiple generators (some connected to distribution) and multiple transmission or distribution companies

4 This is adapted from the glossary provided at the National Power Portal (https://npp.gov.in/glossary) and the ‘Guidelines for computation of AT&C losses’ prepared by the CEA in 2017 (http://www.cea.nic.in/reports/others/god/dpd/guidelines_atc_loss.pdf). As mentioned, Primer provides a simplified description and actual calculation would consider additional factors like electricity duty, state government subsidy, arrears collection etc.

5 From the Annexure 2.8.1 and Annexure 5.2.6 of the PFC report on the performance of state power utilities, 2013-14 to 2015-16, available at: http://www.pfcindia.com/DocumentRepository/ckfinder/files/Operations/Performance_Reports_of_State_Power_Utilities/1_Report%20on%20the%20Performance%20of%20State%20Power%20Utilities%202013-14%20to%202015-16.pdf

⁶ Some studies conducted are: state estimation, which cleans up the data received from substations for further analysis and prepares an estimate of voltages and phase angles at all substations; load flow studies, which calculate power flows on all transmission lines and technical power losses; ‘what if’ contingency studies, which calculate grid behaviour when any one component - the transmission line, transformer or generator - fails; stability studies, which help to design the protection system to protect the equipment in the event of major faults; periodic reporting etc.

7 Based on approximately 0.74 kg/U of coal (this is for sub-critical units, it is lower at 0.61 kg/U for super-critical units) and 2500 tonnes of coal per train.

⁸ Assuming 5 litres of water/U for a wet cooling tower type plant, to make up for evaporation. Water use will be only 15-20% of this for a dry cooling system, but such stations will be costly. Per-capita water consumption by homes is around 100 litres/day/person, and the requirement as per Bureau of Indian Standards is 200 litres/day/person (See Shaban, A & Sharma, R N. (2007). Water Consumption Patterns in Domestic Households in Major Cities. Economic & Political Weekly, 42(23), pp. 2190-2197.)

⁹ Typically coal based units operate at 85% capacity or higher, but from 2016, it has been suggested by the CERC and CEA that the technical minimum capacity for multi-state thermal units should be 55%. These are likely to be implemented in all states. There are facilities to financially compensate the project for efficiency reduction while operating below 85% capacity. These details are available at the CERC website, for example, the IEGC amendment 2016 (see 6.3 B of the regulation available at: http://www.cercind.gov.in/2016/regulation/124_1.pdf )

¹⁰ To appreciate this, think of a goods train with many compartments and hauled by 2 engines. When the train reaches an incline, it starts to slow down. Both engines increase their power output to arrest this slowdown and the train continues to climb at a reduced speed.

11 The national load dispatcher, POSOCO has suggested to CERC in 2017 that there is a need to suitably replace the terms Free Governor Mode of Operation (FGMO) and Restricted Governor Mode of Operation (RGMO) with the term ‘Primary frequency control with droop’, since these terms are not used internationally. They feel that RGMO, introduced by CERC in May 2010, is a non-standard solution, and has led to several generators going for retrofits with little and different understanding of the stipulation in the grid code. Please see: http://www.cercind.gov.in/2017/draft_reg/GC-copy/Power%20System%20Operation%20Corporation%20Limited%20(POSOCO).pdf

12 Let us again look at our train climbing the hill (with many compartments and hauled by 2 engines). After stabilising the climbing journey at a lower speed, the engines may again increase their power output a little so that the train starts moving at the speed at which it was moving when it approached the hill. Sometimes this may not be possible, that is, climbing would be possible only at a lower speed.

13 Soder, L. (2002). Explaining Power System Operation to Non-engineers. IEEE Power Engineering Review, 42(4), pp. 25-27, available at: http://www.eps.ee.kth.se/personal/lennart/lennart_bike_2002.pdf and Fassbinder, S. & De Wachter, B. (2005), Electrical System as a Tandem Bicycle. Retrieved from http://www.gonder.org.tr/wp-content/uploads/2015/04/ElectricityTandem.pdf, or http://www.leonardo-energy.org.

¹⁴ Those interested can read a detailed report on grid disturbance available at http://www.cercind.gov.in/2012/orders/Final_Report_Grid_Disturbance.pdf.

¹⁵ Those interested can read short articles available at http://mentalfloss.com/article/57769/12-biggest-electrical-blackouts-history and https://en.wikipedia.org/wiki/List_of_major_power_outages.

5 : Overview of the electricity sector: Brief history and major players

The generation, transmission, distribution and consumption of electricity involves multiple steps, affects and is affected by many other sectors and hence, involves many actors. The laws, government policies, regulations and court judgments, all affect the functioning of the electricity sector. In this chapter we provide an introduction to the key players in the sector and their roles.

This chapter provides an overview of the major players in the power sector and their roles. We start with a brief history of the Indian power sector, with greater attention to the last few decades. We also provide the current status of the sector in terms of generation capacity, ownership patterns, market operations and fuel use.

5.1 Brief History

5.1.1 Independence to 1991

Before independence, nearly 80% of the generation capacity in the country was owned by private companies and local authorities, and electrification was limited to important urban and industrial areas. These companies were governed under the Indian Electricity Act 1910, which dealt with the operation and regulation of private electricity companies. After independence, electricity was placed in the concurrent list of the Constitution of India, which empowered both the central and state governments to legislate on the subject. The Electricity (Supply) Act of 1948 mandated state governments to set up State Electricity Boards (SEBs), which were formed in the 1950s to extend electricity supply beyond cities. SEBs became quasi-commercial, semi-autonomous bodies.¹ These were vertically integrated entities catering to the generation, transmission and distribution needs of the particular state, and thus, were government owned monopoly service providers in their respective states. Post-independence nationalisation saw several private companies being taken over by electricity boards.

By 1991, the electricity boards controlled 70% of electricity generation and almost all of the distribution, except a few pockets of private distribution in cities such as Mumbai, Kolkata, Surat and Ahmedabad. The electricity boards were authorised to set tariffs and were in charge of state level planning. The central government, acting through its Ministry of Power, was responsible for long term planning and policy, technical clearances and project approvals. The Central Electricity Authority (CEA) set up by the central government in 1951, continues to have an important role to play in national level planning, regulation and data collection. All electricity companies (utilities) were required to approach the CEA for approval for schemes involving capital expenditure exceeding a certain limit. With a view to augment generation capacity and provide an inter-connected regional and national grid, the central government set up national generation companies (NTPC, NHPC) in the 1970s as well as the Power Grid Corporation of India Ltd (POWERGRID) in 1989 by separating the transmission function from NTPC. Figure 5.1 depicts the institutional structure of the Indian Power Sector during this period.

While the SEBs of some states performed satisfactorily till the 1980s, adding capacity and extending the grid to non-electrified areas, their performance soon began to deteriorate and by 1991, there was a crisis in the electricity sector.

Figure 5.1: Institutional structure of the Indian power sector before reforms

Source: Prayas (Energy Group)

5.1.2 1991 to 2003

The Liberalisation, Privatisation and Globalisation era brought reforms in the electricity sector from 1990s onwards. These reforms were meant to maintain a distance between the government and the utilities, as well as bring in private participation and competitive pressure to improve the functioning of utilities. The reforms began in the generation sector, where independent power producers (IPPs) were allowed to establish generating stations and sell power to the SEBs. Generation was considered more amenable to competition, while transmission and distribution were allowed to remain ‘natural monopolies’. The opening up of the generation segment to competition was followed by the unbundling of the vertically integrated SEBs into their constituent parts - generation, transmission and distribution - as well as the establishment of electricity regulatory commissions (ERCs). Odisha was the first state to undertake these reforms, and it went even further and privatised its distribution segment in 1999. Many states followed with restructuring of their electricity boards, but only Delhi privatised its distribution segment in 2002. The Electricity Regulatory Commissions Act was passed in 1998 and provided for the establishment of state level and central level ERCs for regulating the operations of private as well as state government companies. Chapter 9 analyses the reforms since the 1990s and their outcomes in more detail.

5.1.3 2003 onwards

The Electricity Act 2003 (E Act) marked a watershed in the history of the Indian power sector and has had profound impacts. The E Act de-licensed generation and allowed for captive generation plants to be set up; introduced open access in India and recognised trading of electricity as a distinct activity; and placed the ERCs at the heart of the functioning of the electricity sector. It overrode all existing legislation governing the sector, namely the Indian Electricity Act 1910, the Electricity Supply Act 1948 and the Electricity Regulatory Commissions Act 1998, and currently provides the national legal framework governing the electricity sector (See Box 5.1 The E Act for more).

Box 5.1: The Electricity Act (2003)

The E Act provides the legal framework that governs the electricity sector in all of India, except the state of Jammu and Kashmir. Passed in 2003, it replaces the older electricity sector laws and is applicable across the country. The Act aims to move towards a more competitive electricity sector with multiple buyers and sellers. In this regard, it de-licensed generation in order to increase the sources and quantum of electricity generation. In addition, it allows for multiple distribution licensees, captive generation as well as open access to increase electricity supply options for consumers. Major amendments were proposed to this Act in 2014 and 2018, but are yet to be passed.

In moving towards a more market determined tariff, the E Act states that the electricity tariff should progressively reflect the cost of supply of electricity. It further states that cross subsidies should be reduced. The E Act also makes provisions for competitive bidding for the discovery of economical generation tariffs (Section 63 of the Act). It recognises electricity trading as a distinct activity and empowers ERCs to issue licenses for it. However, to ensure impartial system operation, it bars transmission companies and load dispatch centres from trading in electricity. In an unbundled electricity sector with competing generation companies, the load dispatch centres and transmission companies need to be independent to provide a level playing field through transparent system operation as well as open access to transmission lines. Since load dispatch centres oversee grid operation, determine which generator should generate electricity and manage load shedding, they would have a huge advantage over others if they were allowed to trade electricity. Similarly, transmission companies are supposed to provide open access to generators and consumers as well as transmit electricity without a stake, and hence, are also barred from trading electricity. The E Act also proved a watershed for promoting renewable energy with its provision for setting specific minimum targets for renewable energy procurement.

Finally, the E Act mandates the establishment of regulatory commissions and empowers them to make regulations, grant licenses and determine tariff. These commissions are supposed to make independent decisions based on technical, legal and economic principles insulated from political considerations.

To understand how the provisions of the E Act actually played out, see Chapter 9.

Since 2003, important changes have occurred in the power sector. The major ones are listed below:

With the exception of Arunachal Pradesh, Manipur, Mizoram, Nagaland, Sikkim, Goa, Himachal Pradesh, Kerala, and Jammu and Kashmir, all states have unbundled their SEBs to form separate companies.

As of 2018, all states and union territories have established ERCs, of which there are two joint ERCs shared by small states and union territories.²

India’s installed capacity has increased from 132 GW in 2007 to 344 GW in 2018. This includes the capacity with public and private electricity companies, but does not include the 22 GW of captive capacity in 2007 which increased to 55 GW in 2018. The share of private companies in the utility capacity increased from 13% to 45% during the same period. The installed capacity continues to be predominantly coal based (about 60%).

The per-capita electricity consumption of the country was 329 units per year in 1990. It is estimated to have increased to 1149 units per year by 2018, though it still remains one-third of the global average.

Village electrification has increased from 81% in 1990 to 100% as of April 2018, and household electrification has increased from 42% to 95% during the same period.

With the southern grid joining the inter-connected regional grids, the national grid was established on December 31, 2013.

Transmission and distribution losses have remained the same - they were 23% in 1990, went up to 34% in 2002, only to come down to 21% by the end of 2018.

Energy shortages have reduced - the peak shortage was 16.66% and the energy shortage was 7.92% in 1990. This has declined to 2% and 0.7% respectively in 2018. In fact, many states are reporting surplus power.

See Box 5.2 A timeline of the Indian power sector for the major milestones in the Indian power sector before and after independence.

Box 5.2: A timeline of the Indian power sector

Before independence:

1879: Electric lighting is demonstrated in Kolkata.

1897: First generating station (a 130 kW hydro-electric station) is set up near Darjeeling.

1899: The first thermal generating station is set up in Kolkata. With electric lights and fans, Kolkata becomes the first electrified city in India, followed by Mumbai. New York is electrified in 1882 and London in 1888.

1900 - 1920: Generating stations are set up at Khopoli in Maharashtra (set up by Tatas to supply power to Mumbai), Sivasamudram in Mysore (to supply power to Kolar goldfields),Mettur dam in Madras (to power the city of Chennai), etc. A majority of these generation and distribution companies are privately owned.

1910: The Indian Electricity (Supply) Act lays down the rules under which states are to give licenses to (private) companies to supply power.

1935: The Government of India Act places electricity in the concurrent list.

1944: British India has an installed capacity of 1280 MW, of which the presidencies of Bengal and Bombay (both private) account for more than 52% of the total capacity.

After independence:

1948: The Electricity (Supply) Act, similar to an Act in the UK, is passed to extend electricity beyond urban centres. The Act provides for the formation and regulation of State Electricity Boards (SEBs). India has an installed capacity of 1713 MW. Electrification is limited to cities and larger towns, and a mere 0.5% of Indian villages are electrified.

1951: 45% of the total electricity is produced by private utilities (i.e. vertically integrated private companies).

1956: The Industry Policy Resolution is passed, according to which generation and distribution of electricity is to be undertaken by the government. The CEA is to coordinate the sector. Once State Electricity Boards (SEBs) are set up, very few private distribution companies remain.

1960 - 90: SEBs are set up as vertically integrated entities and begin to dominate the electricity sector. By the 1970s, SEBs produce 81% of electricity in the country. Electricity is primarily supplied for industrialisation with industry consumption being the highest and its tariff being the lowest till 1970.³ Many corporations are set up: the River Valley Corporations (DVC, BBMB), NLC (lignite based power), DAE (nuclear power), REC (to give thrust to rural electrification), central generating companies (NTPC, NHPC, NEEPCO), and the central transmission company (POWERGRID). External funding is obtained (from international financing institutions like the World Bank) for generation and big transmission projects. From the mid-1970s, there is a greater focus in some states on pump set electrification. Low or flat rate tariffs for power for agriculture are announced in many states (Karnataka, Tamil Nadu, Punjab, Andhra Pradesh, etc.) from the 1980s. The financial status of SEBs starts deteriorating from the 1980s.

1990 - 2002: After economic liberalisation in 1991, private generation is encouraged through Independent Power Producers (IPPs). The Electricity Regulatory Commissions Act is passed in 1998. The Central Electricity Regulatory Commission (CERC) and State Electricity Regulatory Commissions (State ERCs) are set up. External funding for sector reforms is obtained from the World Bank, the Asian Development Bank, etc. Some of the SEBs are unbundled. Distribution in Odisha and Delhi is privatised. However, the reforms neglect rural electrification.

2003: The E Act lays a strong emphasis on competition, de-licensed generation, introduces parallel licenses, open access and electricity trading, mandates the establishment of electricity regulatory commissions, unbundled electricity boards, and institutionalised mechanisms for consumer grievance redressal.

2003-2018: Electricity regulatory commissions and consumer grievance redressal forums are established, and the position of an ombudsman institutionalised. There is a massive increase in installed capacity, especially private capacity, which reduced shortages. Competitive bidding for capacity started. Massive household and rural electrification programmes were initiated. Open access and captive power generation took off. Electricity markets are introduced. There is also an increase in renewable energy capacity.

The increasing size and complexity of the electricity sector has resulted in a large number of core and affiliate players in the sector. The following sections provide their brief description.

5.2 State level players in the power sector

This section starts with a short discussion on the different roles of the central and state governments in the electricity sector and then proceeds to provide an overview of the different state level players in the sector.

The centre and the states: Where do they come in?

As mentioned above, electricity is in the concurrent list of the Constitution of India. This has resulted in the unique design of the electricity sector, with both the central and state governments playing a role. The state government is involved in the generation, transmission and distribution functions within its state boundaries through its state-owned companies. It makes policies, provides budgetary support and, as mentioned, is the owner and manager of the generation, transmission and distribution companies in the state. It is also responsible for appointing the chairpersons, members and secretaries of the state electricity regulatory commissions. The central government through its companies operates multi-state generating stations, inter-state transmission lines, and provides financial support for energy projects and programmes. It is also responsible for preparing the overall national legal and policy framework, regulatory and safety guidelines, implementing centrally sponsored programmes, and planning at the national level. It also appoints the chairperson and members of the CERC and the Appellate Tribunal for Electricity. You will learn more about these different players as you read on.

Given the present structure of the sector, the state government, its electricity companies and institutions are the entities closest to consumers. Figure 5.2 is a schematic for the organisation of a typical state electricity sector, wherein electricity is generated in generating stations, then transmitted via transmission towers to the distribution periphery, from where it is distributed using the distribution infrastructure (transformers, underground or overhead wires) to the end consumers - households, industries, businesses, agriculture, etc. The operation of power generation and transmission is coordinated by the State Load Despatch Centre (SLDC). The state sector is regulated by the State Electricity Regulatory Commission and monitored by the state government. We begin by looking at the key state-level players in the power sector.

Figure 5.2: A typical state electricity sector

Source: Prayas (Energy Group)

Notes :

1. Generation and transmission companies can be owned by the state government, the central government or by private companies.

2. Distribution companies are mostly owned by the state government and, in some cases, by private companies.

3. The Load Dispatch Centres are independent bodies.

5.2.1 Distribution companies

Distribution companies (or DISCOMs) are the first point of contact between the consumers and the electricity sector. They are responsible for supplying electricity as well as for metering, billing, supply quality and services which directly affect the use of electricity by consumers. Under Indian electricity law, electricity distribution consists of both the wires system (the distribution substations as well as the wires overhead or underground) and electricity supply. Under the E Act, the distribution business is a licensed activity. A ‘licensed activity’ means that the company looking to undertake the distribution of electricity in a particular area can do so only after receiving a license for this purpose from the state electricity regulatory commission. Distribution system voltages are below 66 kV. See Box 5.3 for the typical organisation of a DISCOM.

While distribution of electricity in India is mostly carried out by state government owned companies, there have been many changes since the days of the SEBs and today there is considerable diversity in the distribution segment.⁴ States that unbundled their electricity boards either opted for a single state DISCOM (like Maharashtra) or multiple DISCOMs (states like Gujarat, Karnataka and MP). Some states combined the generation and distribution functions (Tamil Nadu), while others continued with the SEB model (Kerala, Jammu and Kashmir, Goa). Private DISCOMs operate in certain cities, such as Mumbai, Kolkata, Ahmedabad, Surat, Greater Noida and Delhi. There are also a few municipally owned DISCOMs (BEST in Mumbai, NDMC in Delhi), rural electricity supply cooperatives, and some areas managed by the Military Engineering Services. Distribution companies can also contract out specific areas in their licensed area to distribution franchisees (See Box 5.4 Input-based distribution franchisees for more). Thus, at present, there are 41 state owned DISCOMs, nine private DISCOMs and 10 - 15 urban distribution franchisees. In addition, certain other entities have ‘deemed distribution licensee’ status under the E Act. Thus, the Indian Railways has been a deemed distribution licensee since November 2015, and the developers of Special Economic Zones (SEZs) are deemed distribution licensees for their SEZs.⁵

DISCOMs buy power from generation companies with a variety of ownership patterns and fuel sources. Thus, the power purchase basket of a typical DISCOM could include power plants of its state generation company, central generating companies like the National Thermal Power Corporation (NTPC), as well as private generating stations. Generation sources could include a mix of coal, gas, nuclear, hydro and renewable energy such as wind and solar. At present, it is mandatory for DISCOMs to purchase a certain percentage of their energy from renewable sources under the Renewable Purchase Obligation (RPO).

Box 5.3: Typical organisation of a DISCOM

DISCOMs function under a license issued by their State Electricity Regulatory Commission. If it is state-owned, then the state electricity/energy department also supervises the functioning of the DISCOM. The area of operation of a typical DISCOM covers 4 - 6 districts. It is headed by a Chairman and Managing Director (CMD), with two or three directors reporting to her. For convenience of operation, the distribution system under a company is divided into two or three zones headed by a Chief General Manager or Chief Engineer or Executive Director. Under each zone, there are two or three circles (each covering a district or a part of a big city) headed by a Superintending Engineer (SE). In each circle there are three or four divisions (each covering two or three taluks), headed by a Divisional Engineer (DE) who is responsible for three or four subdivisions (covering a taluk, headed by an Assistant DE), which in turn have three or four sections headed by an Assistant Engineer (AE). Each section will have a few subsections covering a cluster of villages or a city suburb. There will be linesmen, meter readers and repair crew to assist in the field work. There is a parallel system for metering, billing and revenue collection with meter readers, billing clerks and accounting officers. In many distribution companies, functions like metering, billing and repair are subcontracted out.

Grievance redressal

Under the E Act 2003, all DISCOMs are mandated to provide a forum for redressal of consumer grievances.⁶ For such redressal, the DISCOM must establish a consumer grievance redressal forum (CGRFs), and the state ERC must appoint an Ombudsman to hear appeals against CGRF orders. In certain states the internal complaint handling system of the DISCOM is the first step in the redressal process and precedes the CGRF, leading to a three-tiered grievance redressal mechanism (See Figure 5.3). Consumers have a choice of approaching the High Court if not satisfied with the decision of the Ombudsman. At each level (except the High Court), the responsible authority is required to come up with an order within a time period specified by the regulations of their ERC. While the basic institutional setup is the same, the details of the structure and processes differ from state to state. In addition to grievance redressal, the
E Act also empowers the ERCs to put out standards of performance to be followed by the DISCOMs. Failure to follow the standards can result in penalisation and the DISCOMs have to submit periodic reports on their level of performance vis-à-vis the standards (Section 59 of E Act).

Figure 5.3: Three-tiered grievance redressal mechanism

Source: Prayas (Energy Group)

Box 5.4: Input-based distribution franchisees

Private participation through franchisees is a means of outsourcing various functions of the DISCOM. An input based franchisee is a type of franchisee model in which the DISCOM continues to provide supply but all the other distribution functions such as metering, billing, capital expenditure for maintaining the network are undertaken by the franchisee. The main objective behind introducing the franchisee is to reduce losses and increase collection efficiency, mostly in chronic high loss making areas. Starting with Bhiwandi in 2007, franchisees now operate in around 15 urban locations in the country including Agra, Nagpur and Kota.

DISCOMs select franchisees through competitive bidding based on ‘input rates’ - the rate the franchisee is willing to pay the DISCOM for power supply. The rate quoted by the franchisee is based on an assumption of a certain distribution loss level which will make the business financially viable. The franchisee is required to continue charging the same tariff as the DISCOM. In order to ensure that an increase in DISCOM tariff does not lead to an increase in franchisee profits, the input rate is also linked to the average tariff of the DISCOM. This model is supposed to incentivise the franchisee to reduce AT&C losses (explained in Chapter 4), improve billing and collection systems and invest in network improvement. The DISCOM receives the input rate and is hence assured a fixed recovery from the area.

Experience with the franchisee model has been mixed. While a steep reduction in losses is claimed in many franchisee areas, lack of proper data makes further analysis difficult. In addition, the bidding process is plagued by several problems including the dilution of contract terms after bidding. In some cases, delayed take-over of franchisees and payment of dues to the DISCOMs has resulted in the termination of certain franchisee contracts. Questions have also been raised about the regulatory scrutiny of franchisees.

In addition to input-based distribution franchisees, other models have been implemented such as rural franchisees which are appointed only for billing and collection purposes, as part of the rural electrification program, RGGVY. It was reported in 2013 that there were 2 lakh village level rural franchisees operating in the country. But subsequent reports indicate that many are not operational and current reports on rural electrification do not include such franchisees. In Odisha, there has been moves to introduce rural franchisees, covering large rural areas.

5.2.2 State transmission companies

As mentioned above, transmission wires carry electricity from generation stations to the distribution periphery. Like distribution, transmission is also a licensed activity under the E Act. States which have unbundled their electricity boards have their own transmission company, which functions as the State Transmission Utility (STU) under the E Act. STUs are responsible for ensuring “the development of an efficient, co-ordinated and economical system of intra-state transmission lines for the smooth flow of electricity from a generating station to load centres”⁷ and hence, are responsible for all transmission planning and coordination in the state. While private participation in transmission is permitted, it has attracted limited interest, and even today the sector is largely run by government owned companies. However, many private generation companies do hold transmission licenses. They operate transmission lines from their power plants to connect them to the grid (such as Adani Power’s transmission license for power evacuation from their Tiroda power plant in Maharashtra), and also maintain transmission lines (such as Tata Power and Reliance Infrastructure in Mumbai). It is worth reiterating here that transmission companies are not allowed to engage in trading of electricity and are expected to provide non-discriminatory open access to their wires.

5.2.3 State generation companies

In India, power is generated by central, state as well as private generation companies using a variety of fuels. Table 5.1 provides the details of installed capacity by ownership and fuel. As can be seen from the table, of the total installed capacity in 2018, state government companies accounted for 30%, central government companies for 25% and private companies 45%. The fuels used can be coal, oil and natural gas, nuclear, or in the case of hydro, flowing water. In terms of the fuel source, thermal generation has the highest installed capacity, accounting for 65%, and most of this capacity is coal based. The share of hydro generation in the mix has reduced from 26% in 2007 to 13% in 2018, while that of renewables has increased. The central government also has an ambitious target of installing 175 GW of renewable energy capacity by 2022.

Table 5.1: Installed generation capacity as on March 2018 (in MW)

Note: Captive generation is not included in this table. It was 54,997 MW in March 2018.

Source: CEA Monthly Executive Summary of the Power Sector for March 2018.

State generation companies own several generating stations. For example, the Maharashtra State Power Generation Company Limited (MSPGCL) has the second largest installed capacity in the country after NTPC. The MSPGCL owns generation stations at Bhusawal, Khaparkheda and Koradi among other places in Maharashtra. In 2017, it owned 10,380 MW of coal based capacity, 672 MW of gas based capacity, 2,585 MW of hydro capacity, and 180 MW of solar capacity.⁸

The type of installed capacity in states also differs. For example, 93% of the installed generation capacity of the Kerala State Electricity Board is based on hydro power, while 82% of the Madhya Pradesh Power Generating Company’s capacity is based on thermal power. Tamil Nadu, on the other hand, has a significant amount of wind based generation capacity (private owned), accounting for 30% of all generation capacity in the state. While technically generation plants are free to sell their electricity to whomsoever they please, state generation stations usually sell their power only to their state distribution companies. Distribution companies then may choose to sell any surplus power to PTC or other utilities. We discuss central and private generation companies in the following section on national level players. See Box 5.5 for some different types of consumers: captive, open access and prosumers.

Box 5.5: Non-traditional consumers

Captive consumers

The E Act de-licensed generation, i.e. any company or person with the necessary fuel resources, approvals and clearances could set up a power generation station anywhere in the country. In addition, it allowed industries to set up captive plants for their own consumption. To qualify as a captive generator, 51% of the electricity generated by the station must be self consumed, i.e. consumed by the factory or office for which the generation station was established as a captive generation station. Moreover, 26% of the equity component of the project must come from the promoters of the project. The captive installed capacity has increased from 22 GW in 2006-07 to 55 GW in 2017-18, i.e. it has more than doubled in less than a decade. On average, captive generators sold about 9% of their generated electricity to utilities in 2017.

Figure 5.4: Captive generation capacity over the years (MW)

Source: Growth of Electricity sector in India - 1947 - 2018, by CEA, and National Electricity Plan, by CEA

Prosumers

Unlike the traditional consumer who consumes electricity from the grid through a one-way flow of electricity, the ‘prosumer’ is someone who produces and consumes electricity. Prosumers generate their own electricity using distributed generation technologies such as a rooftop solar PV. The electricity so produced is either fully or partially consumed by the consumers, while the excess generation, if any, is fed back into the grid. To allow for the metering and billing of the electricity being consumed for the grid and fed into the grid, these consumers are required to install special energy meters that can track the two-way flow of electricity. At the end of the billing period, the consumer pays for the ‘net’ electricity consumed (the difference between the electricity consumed from the grid and the electricity fed into the grid). This mechanism is called ‘net metering’. If the electricity fed into the grid is more than that consumed from the grid, the distribution company credits the prosumer with that surplus for the next billing period. As of July 2017, net metering regulations had been issued by all 29 states and 7 union territories.⁹

Open access consumers

Through the mechanism of ‘open access’, the E Act allows certain consumers (presently those with connected load of 1 MW or more) to choose their supplier while using the wires network of their DISCOM and transmission company for enabling such supply. The open access consumer and supplier agree to purchase power at a mutually negotiated price. The distribution company and the transmission company are compensated for the use of their network. Open access faces resistance from distribution companies since the migration of these (high paying, large) consumers leads to a loss of sales and revenue. In addition, short-term open access (i.e. open access that allows consumers to switch between the DISCOM and the market for a short period) increases uncertainty for the DISCOM and its power procurement planning. Despite barriers and operational hiccups, open access has picked up in various states in recent years.

5.2.4 State load dispatch centres

Load Despatch Centres (LDCs) are responsible for the reliable and efficient operation of the grid. The State LDC is the apex body which ensures integrated operation of the power system in the state and exercises supervision over the intra-state transmission system. State LDCs are responsible for the scheduling and dispatch of electricity as well as accounting for the quantity of electricity transmitted through the intra-state grid. They also enforce the Merit-Order Dispatch for generating plants (See Chapter 4 for details). The E Act gives significant powers to the LDC. Importantly, LDCs have the power to issue directions which have to be followed by all licensees, generation companies and any other person connected with the operation of the grid. LDCs are supposed to be independent and impartial so that the decisions they take are based on ensuring the stability and smooth operation of the grid and nothing else. For the same reasons, they are also barred from trading in electricity. In many states the separation of the LDC from the transmission companies is not complete and hence, LDCs continue to be part of the transmission companies. See Chapter 4 for more details on the functioning of LDCs.

5.2.5 State Electricity Regulatory Commissions

The Electricity Regulatory Commissions (ERCs) are relatively new actors in the power sector, having been established mostly after the year 2000. The ERCs are quasi-judicial bodies that frame regulations and oversee their implementation. ERCs are supposed to provide decision making independent from the government and are also mandated under the E Act to ensure transparency in sector operations and provide opportunities for public participation. The Odisha Electricity Regulatory Commission was the first to be set up in 1996, and today, all states and union territories have ERCs. The E Act put the Electricity Regulatory Commissions (ERCs) at the centre of the functioning of the power sector. ERCs are empowered to regulate almost every aspect of the sector: they set tariffs for generation, transmission, supply, and wheeling; issue licenses for transmission, distribution and electricity trading; and adjudicate on disputes between the various licensees and generation companies. They are also responsible for enabling and facilitating competition in the sector and protecting consumer interest. Since the E Act made public consultation mandatory for a variety of processes at the ERC level (such as grant of licenses, framing of regulations, and tariff determination), these commissions also provide a platform for the public to participate in the regulatory process. ERCs hold public hearings and invite comments on various issues from the public. A State Advisory Committee (SAC), consisting of members representing the interests of commerce, industry, transport, agriculture, labour, consumers, academic and research bodies, advises the state ERCs on major questions of policy, compliance with conditions of license by licensees, protection of consumer interest and electricity supply issues.

5.2.6 State level policy institutions

The state government department of energy formulates state specific policies, provides budgetary support to state owned companies and is responsible for key appointments, such as the chairperson and managing director of the state-owned companies and the chairperson and members of the state ERC. All state-owned electricity companies are under the supervision of the state energy department. The state government is free to implement policies and programmes; however, if these have an implication on tariff or the operations of the electricity company, then it would have to approach the ERC. For example, the state government energy department can decide to implement a policy of providing subsidised electricity to agricultural pump sets. In this case, the tariff for farmers remains the same but the state government will pay the distribution company part of the tariff charged to farmers. However, the state government cannot decide to set the tariff for small households at say Rs 2 per unit. Tariff determination is the responsibility of the state ERC and cannot be carried out by the state government. In addition, most state governments have established energy development agencies, such as the Maharashtra Energy Development Agency or the Assam Energy Development Agency. These agencies function as State Nodal Agencies (SNAs) for renewable energy and work in coordination with the Ministry of New and Renewable Energy (MNRE) at the central level. In 2014, the Association of Renewable Energy Agencies of States (AREAS) was formed by the MNRE and has amongst its 36 members, the renewable energy agencies of states and electricity departments of union territories.

5.2.7 State electricity inspectorate

As per the National Crime Records Bureau, more than 10,000 people die every year due to electricity shocks or fire caused by short circuits.¹⁰ Thus, ensuring safety and preventing electricity accidents is very important. Under the E Act, the state government appoints a Chief Electrical Inspector and other electrical inspectors. The electricity inspectorate is responsible for safety, inspection and enquiry into electricity accidents. In addition, the Central Electricity Authority (CEA) prepares regulations on safety of electricity generation, transmission and distribution, the latest of which is the Central Electricity Authority (Measures relating to safety and electric supply) Regulations 2010, amended in 2011 and 2015. The electrical inspector and DISCOMs are expected to follow these regulations. Electrical inspectors in some states publish periodic reports analysing the electricity accidents. DISCOMs in some states prepare safety manuals and awareness material.

5.3 National level players in the power sector

5.3.1 Generation: Central and Private

Central generation companies include the National Thermal Power Corporation (NTPC) and the National Hydroelectric Power Corporation (NHPC). The NTPC is the largest thermal generation utility in the country with an installed capacity of 51,708 MW¹¹, and the NHPC is the largest organisation for hydropower development in the country with an installed capacity of 6,717 MW.¹² Other central generation companies include Neyveli Lignite Corporation (NLC), the North Eastern Electric Power Corporation (NEEPCO), and the Tehri Hydro-Development Corporation (THDC).

The share of private generation capacity has increased tremendously in the country from 17,113 MW in 2007 to 1,55,511 MW in 2018 (i.e. almost by 22% every year). Till the 1990s, private generation capacity was limited to Tata power stations in Maharashtra, CESC stations in Kolkata, Torrent Power in Gujarat and the captive stations of some industries. Since the opening of the sector to private players in the 1990s, many private players have set up power plants in India. The major private players in the country include Tata Power (with an installed capacity of 10,549 MW¹³), Adani Power (10,480 MW)¹⁴ and Reliance Power (~6,400 MW).¹⁵ In 2006, the central government launched the Ultra Mega Power Projects (UMPP) policy. UMPPs are large projects, around 4000 MW each, being developed on Build, Own and Operate (BOO) basis. There are two operational UMPPs in India as of 2017, the Sasan UMPP in Madhya Pradesh operated by Reliance Power and the Mundra UMPP in Gujarat operated by Tata Power. Private companies are also involved in developing hydro-electric projects in the country. For example, JSW’s Himachal Baspa Power Company Ltd (HBPCL) operates the Baspa II (300 MW) and the Karcham Wangtoo (1091 MW) hydro-electric power plants in Himachal Pradesh.

In general, central, state and private companies have thermal (coal and gas), hydro and renewable generation units. Nuclear generation, as of now, is only developed and operated by the central government. The Nuclear Power Corporation of India Limited (NPCIL) and Bharatiya Nabhikiya Vidyut Nigam Limited (BHAVINI), both wholly owned central government entities, are responsible for implementing nuclear power projects in India.

5.3.2 Inter-state transmission

Just as there are state government transmission companies at the state level involved in intra-state transmission, there are also transmission companies at the national level which are involved in the construction and operation of inter-state transmission lines and substations. The Power Grid Corporation of India Limited (POWERGRID) is the Central Transmission Utility (CTU) of India. It undertakes the transmission of electricity through the inter-state transmission network and is responsible for the planning and development of the inter-state transmission system. POWERGRID operates 90% of the inter-state and inter-regional networks in the country.¹⁶ Since 2006, there has been an increase in the number of private players in inter-state transmission. As in the case of intra-state transmission licensees, the inter-state transmission licensees are barred from trading in electricity.

Table 5.2: Transmission ownership as on March 2018

Source : CEA Monthly Report (Transmission), March 2018

5.3.3 Regional and national Load Despatch Centres

State Load Despatch Centres (SLDCs) are connected to the Regional Load Despatch Centres (RLDCs). The RLDCs monitor the operations in a particular regional grid of the country. For example, the Southern Regional LDC located in Bengaluru monitors and coordinates the electricity operations for the Southern India Regional Grid comprising the states of Andhra Pradesh, Telangana, Tamil Nadu, Karnataka, Kerala and the Union Territory of Pondicherry.¹⁷ There are five Regional LDCs - North, East, West, South and North East - or the five regional grids of the country. The five RLDCs are connected to the National Load Dispatch Centre (NLDC). The RLDCs and NLDC are owned, operated and maintained by the Power System Operation Corporation of India (POSOCO). POSOCO was set up in 2010 as a wholly owned subsidiary of POWERGRID with its headquarters in Delhi and made a separate company in 2017. The RLDCs and the NLDC perform the same functions as the State LDCs but for their particular geographical regions. As in the case of SLDCs, the RLDCs and the NLDC cannot trade in electricity. All the LDCs are part of the Forum of Load Despatchers of India (FOLD), which takes up issues of common interest, shares knowledge and allows for technical cooperation between the LDCs.

5.3.4 Market operators

Power trading was recognised as a distinct activity for the first time in the E Act. Since then it has grown specifically in the short-term market, with participation from both intra-state and inter-state traders.

Short-term markets

Short-term market transactions of electricity refer to contracts for sale of electricity which have a duration of less than one year and include electricity traded (1) under bilateral transactions through inter-state trading licensees (only inter-state trade), (2) through the power exchanges (IEX, PXIL), (3) directly by the distribution companies and (4) transacted through the Deviation Settlement Mechanism (DSM) (as explained in Chapter 4). The volume of electricity market transaction has increased from around 12 billion units (BU) in 2004 - 05 (2.2% of total electricity generation) to around 87 BU in 2017 - 18 (7.2% of the total), as shown in Figure 5.6. Inter-state trading licensees such as India Energy Exchange (IEX) and Power Exchange India Limited (PXIL) function as exchanges where power is sold at market determined prices based on bids. A trade not facilitated by the exchange is a bilateral trade and these take place for short-term bidding by distribution companies or on the DEEP platform¹⁸. DISCOMs participate in power exchanges and bilateral transactions.

Intra-state and inter-state traders

Inter-state traders need a trading license to function and since they conduct inter-state trading, they are granted a license and regulated by the CERC. The CERC maintains a registry of inter-state trading licensees and as of 2018, regulates 36 inter-state trading licensees. The PTC India Ltd (formerly Power Trading Corporation of India Limited), set up in 1999 by the central government as a public-private partnership, is the largest power trader in the country. The state ERCs grant licenses for intra-state trading. While intra-state trading is not well monitored, the CERC publishes data on inter-state trading in its Market Monitoring Report.

Figure 5.5: Volume of electricity traded via inter-state traders and power exchanges

Source: Choosing Green, PEG 2017 and Report on short-term power market in India, CERC 2018

5.3.5 Central Electricity Regulatory Commission

Established in 1999, the Central Electricity Regulatory Commission (CERC) regulates all inter-state activities, i.e. activities involving more than one state. Thus, it regulates the operation and management of the regional transmission network, inter-state trading licenses and operations, and determines tariff of central generation plants as well as power plants selling power to more than one state. A Central Advisory Committee (CAC) advises the CERC much in the same way the SAC does the state ERCs. It is worth noting here that there is no hierarchy between the CERC and the state ERC. Their powers and responsibilities are outlined in the E Act and neither is bound by the rulings of the other. The chairpersons of the central and state ERCs constitute the Forum of Regulators (FoR) which works to “harmonise legislation in the power sector” and to share information ”on various issues of common interest and also of common approach”.

5.3.6 Legal Forums

The Appellate Tribunal for Electricity

Under the E Act, any person aggrieved by an order of the ERC can file an appeal with the Appellate Tribunal for Electricity (APTEL). Before the E Act, appeals against orders of the ERCs were made to high courts. However, the APTEL now serves as a dedicated appellate body for such appeals. The APTEL sits in New Delhi and has four members. Under Section 121 of the E Act it also has the power to issue directions to the ERCs for the performance of their statutory functions. The APTEL also functions as the appellate body for the Petroleum and Natural Gas Regulatory Board (PNGRB). Appeals against orders of the APTEL have to be made to the Supreme Court of India.

Consumer Courts, High Courts, the Supreme Court

The E Act does not restrict the rights of consumers or of the companies and corporations involved in the electricity sector to approach High Courts or the Supreme Court for a legal remedy. Writ jurisdiction of the courts applies to the electricity sector as well. However, in approaching the courts, one must be sure of the jurisdictions of the courts vis-à-vis the ERCs and APTEL. For example, a tariff order of the ERC should be challenged in the APTEL. However, issues such as the failure of the ERC to fulfil its legal mandate or lack of adherence to due process, or any issue concerning any particular aspect of the ERC regulations, if it is in contradiction with the E Act provisions or prevailing legal practices and principles, can be challenged before the High Court. In addition, the consumer also has the right to approach the consumer courts for matters related to the sale and consumption of electricity. There rights are not curtailed by the introduction of the E Act and its grievance redressal machinery. The Consumer Protection Act 1986 provides for the establishment of a three-tier consumer dispute redressal machinery at the district, state and national levels. These courts have jurisdiction over all goods and services, including electricity, provided by public as well as private players, and consumers can complain at these forums about poor quality of services by a distribution company.

5.3.7 National Policy

The Ministry of Power (MoP) coordinates policy matters for the power sector at the national level. It makes rules and policies under the E Act. The National Electricity Policy, the National Tariff Policy and the Rural Electrification Policy are all prepared by the MoP. The Central Electricity Authority (CEA) operates under the aegis of the MoP, and provides technical services (such as demand forecasting, preparing regulations, undertaking technical clearance for hydro projects) as well as data management services to the central ministry. The Bureau of Energy Efficiency (BEE) also operates under the MoP and works on the policy framework and directions for the national energy conservation activities. It was setup under the Electricity Conservation Act of 2001 and is responsible for ensuring implementation of the various energy efficiency related measures. The Energy Efficiency Services Ltd (EESL) was formed by the MoP as a joint venture between the NTPC, PFC, REC and POWERGRID to assist the central and state governments in implementing the BEE’s programmes.¹⁹

The Ministry of New and Renewable Energy (MNRE) is the central government ministry responsible for all matters related to new and renewable energy. The Solar Energy Corporation of India (SECI), established in 2011, operates under the MNRE. Originally established to facilitate the implementation of the Jawaharlal Nehru National Solar Mission (JNNSM), its mandate has since been enlarged to cover other renewable energy technologies as well. The SECI implements schemes of large-scale grid connected projects, solar-park schemes, etc.

Finally, the MoP guidelines on cross-border trade of electricity, CERC draft regulations, and CEA Conduct of Business Rules regulate the import and export of electricity between India and other countries.²⁰

5.4 Other key players and inter-linkages

5.4.1 Engineering and financing

Financing

Conventional generation and transmission projects are capital intensive and have a long gestation period. Thus, there is a need for injection of funds for a long period of time. Several agencies are involved in providing funding to the power sector. The Power Finance Corporation (PFC, set up in 1986) and the Rural Electrification Corporation (REC, set up in 1969) are two non-banking financial corporations under the Ministry of Power that are involved in financing power sector investment. These corporations are mostly involved in financing state owned projects, and mainly generation projects.²¹ The PFC is the single largest lender in the Indian electricity sector, disbursed around Rs 64,000 crore loans in 2017-18 to the sector and supported 23% of installed capacity as of 2011.²² The Indian Renewable Energy Development Agency (IREDA) is also a non-banking financial institution for extending financing to renewable energy projects. In addition, national commercial banks also provide loans to power projects. Public sector commercial banks, led by the State Bank of India (SBI), are major lenders to power projects. Private commercial banks are also allowed to lend to power projects but have done so to a lesser extent. ICICI Bank and Axis Bank are two private sector banks providing loans to the power sector. International financial institutions also provide financial support to power projects in the country. These include the World Bank, the International Monetary Fund (IMF), the Asian Development Bank (ADB), as well as the Bank of China, the Japan Bank of International Corporation (JBIC) and the Export Import Bank of the United States (EXIM). Credit rating agencies in India include the big three: CRISIL, ICRA and CARE.

Engineering and manufacturing

The government owned Bharat Heavy Electricals Limited (BHEL) is one of the largest power equipment manufacturers in India. BHEL manufactures boilers, turbines, generators and a host of auxiliary equipment for power stations. As on March 31, 2013, BHEL had supplied power generation sets worth 1,15,500 MW which accounted for 57% of the overall installed power generation capacity of India at the time.²³ While BHEL continues to be the biggest player, its market share has been declining - it fell from 65% at the end of 2007 to 58% by the end of 2012. The market share of private companies as well as foreign companies has been rising. Big private Indian companies in the sector include Larson and Toubro (L&T) and Paharpur Cooling Towers and Cethar Ltd (Trichy). Foreign companies such as Siemens, Alstom, Doosan Heavy Industries and Construction (Korea), Technopromexport (Russia), etc also supply in India. The three biggest thermal power equipment manufacturers in China - Dongfang Electric Company (China), Shanghai Electric Company (China), and Harbin Electric Company (China) - have a significant market share in India.²⁴ In addition, many companies have formed joint ventures for the supply of boilers and turbine generators to power plants. Several companies are involved in the manufacture of solar PV cells and modules. In India, Tata Power Solar Systems Ltd, Jupiter International Ltd, and Emmvee Photovoltaic Private Ltd are the biggest names. However, most solar modules are imported from Taiwan and China. Trina Solar Limited and Jinko Solar are some of the Chinese companies involved in solar PV module export to India.²⁵ Table 5.3 provides a list of some of the major players in the industry.

Table 5.3: Some major players in the manufacturing of power equipment

Field

Activity

Companies

Generation - Equipment

Thermal plant equipment manufacture

BHEL, Larson & Toubro, Siemens, General Electric (GE), Alstom, Paharpur, Cethar Ltd, Doosan Heavy Industries and Construction (Korea), Dongfang Electric Company (China), Shanghai Electric Company (China), and Harbin Electric Company (China)

PV cell and module manufacture

Tata Power Solar Systems Ltd, Jupiter International Ltd, Emmvee Photovoltaic Pvt Ltd, Kohima Solar, Radiant Solar, Trina Solar (China), Jinko Solar (China)

Hydro plant

BHEL, Alstom Projects (India), Alstom Power Hydraulique (France)

Generation - Engineering, Procurement and Construction (EPC)

Planning, erection, commissioning, civil

works, O&M, R&M

Many manufacturers from above: BHEL, L&T, Tata, Doosan (Korea), Shanghai Electric (China), HCC Ltd (Mumbai), Lanco Infratech (India)

Transmission and Distribution - Equipment and Engineering

Towers, transformers, substations, cables and conductors

BHEL, Siemens, Alstom, ABB (Sweden), L&T, RPG, Jyoti, Finolex, CCI, Vijay Electricals

Consumer - Electrical equipment

Motors, lights, heating systems, cooling systems

Siemens, Philips, Bajaj, Voltas, Bluestar, Anchor, Crompton, Godrej, Khaitan, many MNCs

Billing and metering

Metering, billing systems

EE, Schlumberger, SEMS, SANDS, BHEL

Protection, control and instrumentation systems

Relays, circuit breakers, control and instrumentation

EE, L&T, Andrew Yule, Easum Rayrolle, Automatic Electric, Foxboro, Yokogawwa, SquareD, Keltron, BHEL

Energy management and system management

Control centres, management of distribution, consultancy, training

ABB, GE, Alstom, Siemens, BHEL, NELCO, CMC, CDAC, Global Energy

Corporate services

Consultancy, training

ASCI, MN Dastur, PWC, EY, KPMG, SNC, Lavelin, Deloitte, TEC, Engineers India, TCS, Feedback ventures, IDAM, ABPS.

Note: There are many other players in each of the segments mentioned in the table and this is by no means a comprehensive list.

5.4.2 Fuel Supply

All generation, save renewable and hydro-electric projects, requires fuel to generate electricity. Thus, the fuel sector has important inter-linkages with the electricity generation sector. We will concentrate on the ministries and major companies involved and the import of fuel to give readers an idea of the functioning of the broader fuel sector in India. However, a more detailed examination of the fuel sector is beyond the scope of this primer.

Coal

Coal-based generation projects accounts for 57% of installed capacity in the country and produce nearly two-thirds of the electricity in the country. The Ministry of Coal under the central government is the ministry responsible for the coal sector in India. The sector was nationalised in the 1970s with the Coal Mining (Nationalisation) Act 1973. Subsequent to the nationalisation, the public sector coal mining behemoth Coal India Limited (CIL) was born. CIL today is the world’s largest coal miner and accounted for 84% of the coal production in India in 2016 - 17 (See Figure 5.7). In addition to CIL, the other public sector companies in the sector include Singareni Coal Collieries Ltd (SCCL) and the Neyveli Lignite Corporation (NLC). Post nationalisation, other than the central or state government and its companies, private players were not allowed to mine coal for commercial purposes, i.e. mining coal for sale in the market. Companies requiring coal thus approach the Ministry of Coal for coal via ‘linkages’ from CIL and SCCL mines. However, some coal mines were allocated to companies involved in certain ‘end-uses’, such as production of steel and power generation for ‘captive’ mining. These companies could mine and use the coal only in their end-use plants. The Coal Mining (Special Provisions) Act passed in 2015 made amendments to existing legislation and legalised coal mining for commercial purposes by entities other than the central government.

Coal is available in relative abundance in the country and is expected to remain a significant contributor to India’s overall energy basket in the short to medium term. In addition to domestic production, a significant quantity of coal is imported. For example, India imported 200 MT (24%) of its coal requirement in 2015 - 16, of which around 44 MT is coking coal (for steel production) and the rest non-coking coal. Indonesia is the biggest exporter of non-coking coal to India, while Australia is the biggest exporter of coking coal to India.

Figure 5.6: Coal production in India in 2016-17

Source: Provisional Coal Statistics,2016-2017

Natural gas

Natural gas based generation capacity accounted for around 8% of the total installed capacity in 2017 and plays a small role in India’s electricity sector. Nevertheless, natural gas is the second most used fossil fuel after coal for power plants. India has poor natural gas reserves and accounts for 0.8% of the world’s proven reserves and annual production. Thus, imports accounted for 45% of the natural gas consumed in India in 2016. The Ministry of Petroleum and Natural Gas under the central government is responsible for the natural gas sector in India. A gas based generation plant can either access domestic gas (from blocks administered under different regimes -nomination, pre-NELP, New Exploration Licensing Policy (NELP) and Hydrocarbon Exploration and Licensing Policy (HELP)) or import Liquefied Natural Gas (LNG). In the future, gas could also be sourced via international pipelines, such as the Turkmenistan-Afghanistan-Pakistan-India pipeline (TAPI). Central, state and private companies are involved in the exploration and production of natural gas. The major sector entities include the Oil and Natural Gas Corporation Limited (ONGC), GAIL (India) Limited and Reliance Industries Limited (RIL). In addition, companies, both private and public, have also set up LNG receiving and re-gasification terminals for importing LNG. For example, a joint venture of the public sector oil companies (promoters are BPCL, GAIL India, IOCL and ONGC), Petronet LNG Ltd, has LNG terminals in Dahej (Gujarat) and Kochi (Kerala). These companies enter into contracts with direct bulk consumers, such as power plants, and also trade in LNG on domestic and international platforms. India is the fourth largest LNG importer in the world.

Nuclear

Nuclear energy in India falls under the aegis of the Department of Atomic Energy (DAE) of the Government of India. As mentioned above, nuclear power is solely generated by the central government, and NPCIL and BHAVINI are responsible for nuclear power generation in the country. India has 6,780 MW of installed nuclear based generation capacity in 2018.

5.4.3 Distributed energy providers

There are also organisations that are working to provide electricity access and related services to non-electrified remote rural areas using off-grid and decentralised generation (using solar PV, biogas, etc.). Husk Power, SELCO Solar and Gram Oorja are some such organisations.

5.4.4 Research and professional bodies

There are many government-run and private research and training institutions working on energy issues. The National Institution for Transforming India (NITI Aayog) was set up in 2015 and is the policy think tank of the Government of India. It replaced the Planning Commission of India and undertakes research to provide policy inputs to the government. The Energy Division at NITI manages the India Energy Portal, which houses the India Energy Security Scenarios 2047 as well as the India Energy Dashboards. The Central Power Research Institute (CPRI) is a research facility under the Ministry of Power. The Central Board of Irrigation and Power (CBIP) is involved in standardisation initiatives. The National Power Training Institute (NPTI), the Engineering Staff College of India (ESCI), the Central Institute for Rural Electrification (CIRE), the Yashwantrao Chavan Academy of Development Administration (YASHADA) and the Indian Institution of Technology, Kanpur are some training facilities for working engineers and regulators. The Sustainable Transformation of Rural Areas (SuTRA) centre at the Indian Institute of Science, Bangalore, the Alternate Hydro Energy Centre (AHEC) at the Indian Institute of Technology, Rourkee, and the National Centre for Photovoltaic Research and Education (NCPRE) at the Indian Institute of Technology, Bombay have done significant work on electricity policy and renewable energy. Many institutes offer management degrees in power sector studies and post-graduate degrees in energy systems or regulatory governance. These include the University of Petroleum and Energy Studies (UPES) in Dehradun, the Tata Institute of Social Sciences (TISS) in Mumbai, IIT - Kanpur, Pandit Deendayal Petroleum University - Gandhinagar and The Energy and Resources Institute (TERI) University in Delhi.

There are also many private research organisations working on energy issues, including The Energy and Resources Institute (TERI), the World Resources Institute (WRI), Centre for Study of Science, Technology and Policy (CSTEP), Centre for Science and Environment (CSE), Centre for Policy Research (CPR), Council on Energy, Environment and Water (CEEW) and the Vasudha Foundation to name a few. In addition, some foreign universities have opened centres in India that work on energy related issues, such as the Energy Policy Institute of the University of Chicago in India (EPIC-India).

Professional bodies include the Bureau of Indian Standard (BIS) involved in standardisation efforts, the Institution of Engineers - India (Electrical chapter), the Institution of Electric and Electronic Engineers (IEEE), USA - India Chapter, and the Institution of Electrical Engineers (IEE), UK - India Chapter. These bring out regular publications and organise seminars and conferences on technical issues. There are also portals and discussion groups on the internet.

5.4.5 Trade unions and employee associations

State electricity board employees’ unions have always participated in debates related to the power sector. Some active unions include the West Bengal State Electricity Board Employees and Workers Union, the Maharashtra State Electricity Workers Federation, the Tamil Nadu Electricity Board Engineer’s Union, the Kerala State Electricity Boards Officers’ Association, and the All India Power Engineer’s Federation (AIPEF).

5.4.6 Industry and civil society organisations

Industry and civil society organisations play an important role in advocacy and policy making. The Indian Electrical and Electronics Manufacturing Association (IEEMA) is a representative organization of manufacturers of electrical, industrial electronics and allied equipment. The major industry organisations, such as the Confederation of the Indian Industry (CII), the Federation of Indian Chambers of Commerce and Industry (FICCI) and many state level industry and trade organisations participate in policy initiatives. The Independent Power Producers Association of India (IPPAI) is the association of IPPs in India. The Solar Power Developers Association (SPDA) is the association of solar generators. The National Solar Energy Federation of India (NSEFI) in New Delhi represents solar project developers, manufacturing and engineering companies. The Indian Wind Energy Association (InWEA) is a wind energy generators association. The Forum of Indian Regulators (FOIR) is a voluntary forum for former and current members and chairpersons of regulatory commissions (not restricted to electricity), authorities, and any other organisations connected with public utilities.

From the 1990s, many consumer and voluntary organisations have joined the debates on the power sector. These organisations work on environmental issues, relief and rehabilitation, non-conventional energy systems and policy analysis among other areas. Some organisations working on such policy issues are the Kerala Shastra Sahitya Parishad (KSSP) in Kerala, the Mumbai Grahak Panchayat and Kalpavriksh Environment Action Group in Maharashtra, the Environment Support Group in Bengaluru, the People’s Monitoring Group on Electricity Regulation (PMG) in Hyderabad, Delhi Science Forum (DSF), South Asia Network of Dams, Rivers and People (SANDRP) in New Delhi, the Narmada Bachao Andolan (NBA) in Madhya Pradesh, Maharashtra and Gujarat, the Manthan Adhyayan Kendra in Madhya Pradesh, the Consumer Unity and Trust Society (CUTS) in Rajasthan, Citizen Consumer and Civic Action Group (CAG) in Chennai, and Greenpeace India. There are also many email discussion groups focusing on different areas like technical aspects, policy and regulation, renewable energy and energy efficiency. In addition, many agencies provide commercial newsletters, statistical reports and sector trends.

5.4.7 Environment and electricity

The creation and operation of energy infrastructure, especially conventional generation plants, has serious adverse impacts on the environment as well as human health. Given the various steps involved in setting up infrastructure projects, the inter-linkages with the environment are complex and many, and beyond the scope of this primer. Here we briefly present the major institutions and agencies responsible for managing and regulating environment clearances and land acquisition concerning conventional generation.

Ministry of Environment, Forest and Climate Change

The Ministry of Environment, Forests and Climate Change (MoEFCC) is the nodal agency of the central government responsible for planning, promotion, coordination and implementation of India’s environment and forest related laws, policies and programmes. It is also empowered to grant or reject environment, forest and wildlife clearances to projects and plays a role in monitoring compliance with the clearances.

Environment clearances

An environment clearance is required for all conventional generation²⁶ projects (new projects, expansion or modernisation of existing projects). Projects are classified into category A or B based on the project’s size and capacity. Category A projects require an environment clearance from the MoEFCC. The MoEFCC constitutes sector-specific Environment Appraisal Committees (EACs) which make recommendations to it regarding the grant of clearance. Category B projects require an environment clearance from the State Environment Impact Assessment Authority (SEIAA). The central government in consultation with the state government constitutes the State or Union Territory Level Expert Appraisal Committee (SEAC) which make recommendations regarding clearances to the SEIAA. During the Environment Impact Assessment (EIA) process for a project, its environmental impacts are assessed prior to its implementation. Public consultations are mandatory during the EIA process,²⁷ and public hearings are a part of the consultation and are to be held at or near the site to help ascertain the concerns of the local affected persons. The monitoring cell at the MoEFCC and its 10 regional offices undertake monitoring of cleared projects. All cleared projects must submit half-yearly compliance reports in respect of the stipulated terms and conditions of the environment clearance²⁸. In addition to the environment clearance, projects are also required to obtain a forest clearance from the MoEFCC if their project uses forested land. The process of obtaining this clearance is governed by the Forest (Conservation) Act, 1980.

Pollution control boards

The Central Pollution Control Board (CPCB) is in-charge of air and water quality monitoring and management. The State Pollution Control Boards (SPCBs) implement various legislations with respect to prevention and control of environmental pollution. The SPCBs and the Union Territories Pollution Control Committees (UTPCCs) also organise the public hearings under the EIA process. The district magistrate, district collector, deputy commissioner or her representative as well as a representative of the SPCB/UTPCC supervise and preside over the entire public hearing process. The Pollution Control Boards also issue the ‘Consent to Establish’ and the ‘Consent to Operate’ to projects²⁹.

Land acquisition

The Right to Fair Compensation and Transparency in Land Acquisition, Rehabilitation and Resettlement Act of 2013 (referred to as the LARR Act) replaced the old Land Acquisition Act, 1894 and put in place a new regime for land acquisition in the country. Under the new Act, a social impact assessment has to be carried out in consultation with the panchayat. In addition, the Act states that the collector can only take possession of land after the compensation and resettlement and rehabilitation have been carried out. The Act also requires all private projects or public-private partnership (PPP) projects to seek the consent of 70-80% of the landowners in order for the acquisition to take place. The district administration plays a key role in the acquisition of land and the rehabilitation and resettlement of project affected peoples under the LARR Act.

National Green Tribunal

The National Green Tribunal (NGT) was established in October 2010 to provide effective and expeditious disposal of cases related to the environment and natural resources. It exercises jurisdiction under seven central acts relating to water, air, environment and forest conservation. Any person aggrieved by orders issued under these acts or any application for relief or compensation can be made to the NGT. The granting of Environment Clearance (EC) or Forest Clearance (FC) can also be challenged by filing an application or appeal with the NGT. Appeals against NGT orders are made to the Supreme Court.

5.4.8 District officials

Box 5.3 gives the typical organisation structure of a DISCOM. For most aspects related to electricity supply, consumers need to approach the local DISCOM office. In addition, there are a few more institutions that a citizen should be aware of.

As per the E Act, state governments are required to set up District Vigilance and Monitoring Committees to monitor electrification, quality of service and energy efficiency. The senior most MP is to be the Chair, the District Collector the convenor, and other public representatives and electricity officials are the members. In states like Rajasthan where the Right to Hearing Act, 2012 is in operation, public hearings (called jan sunwai) are held at the district level by the district collector, and all government officials including those of the DISCOM are expected to participate. Many DISCOMs conduct lok adalats (public hearing to dispose complaints) at the district, block or substation levels. In addition, all grievances related to land acquisition for generation, transmission or distribution projects are to be addressed to the district collector.

In cities and towns, the local administration does not have much role in electricity distribution, except in providing street lights and water supply, as well as permitting electricity companies to construct overhead lines or underground cables. When city master plans are being prepared, electricity companies also participate, along with other agencies responsible for water supply, sewerage, transport, land use planning and roads.

Endnotes

¹ SEBs were set up in different states as per the Electricity Supply Act (1948) and were intended to be autonomous bodies. Subsequent amendments to the Act gave powers to the state government to remove the Chairman and members of the Board (Section 10, amended in 1956). Similarly, the sixth schedule, introduced in 1956 amendment, allowed SEBs to make reasonable returns.

² There is one Joint ERC for Manipur and Mizoram, and another for Goa and the union territories.

³ In 1966, the break-up of consumption and tariff was: industry (74% consumption, tariff 5.4 paise/Unit), irrigation (6% consumption, tariff 10.1 paise/Unit), residential (8% consumption, tariff 23 paise/Unit).

⁴ The central government is not involved in distribution of power, save in Union Territories, since the UTs (other than Pondicherry and Delhi) fall under the purview of the central government.

⁵ Indian Railways is a deemed distribution licensee under the third proviso of Section 14 of the E Act, which allows for government entities distributing or trading in power to be deemed licensees without needing to apply for a license. Developers of SEZs are deemed licensees by virtue of a proviso introduced into the E Act by a notification of the Ministry of Commerce under Section 49(1)(b) of the SEZ Act, 2005 on March 3, 2010.

⁶ Section 42 of the E Act.

⁷ Section 39 of the E Act.

⁸ Installed capacity of MSPGCL as on July 20, 2017 from https://www.mahagenco.in/index.php/generation. Accessed on November 17, 2017.

⁹ Read 175 GW - July 2017 update of Prayas (Energy Group), available at http://prayaspune.org/peg/publications/item/356.html for more information.

¹⁰ See the annual reports on Accidental Deaths and Suicides in India, published by the National Crime Records Bureau. Available at http://ncrb.gov.in.

¹¹ NTPC Installed Capacity. Available at http://www.ntpc.co.in/en/power-generation/installed-capacity. Accessed on November 17, 2017.

¹² NHPC Projects (Overview and Power Stations). Available at http://www.nhpcindia.com/projects-overview.htm. Accessed on November 17, 2017.

¹³ TATA Corporate Overview. Available at https://www.tatapower.com/corporate/overview.aspx. Accessed on November 17, 2017.

¹⁴ Adani Power, Businesses, Operational Power Plants. Available at http://www.adanipower.com/businesses/operational-power-plants. Accessed on November 17, 2017.

¹⁵ Reliance Power, Power Projects. Available at http://www.reliancepower.co.in/initiatives_Renewable_energy.html. Accessed on November 17, 2017.

¹⁶ Company Overview, POWERGRID website. Available at http://www.powergridindia.com/company-overview.

¹⁷ See http://www.srldc.in/

¹⁸ DEEP (Discovery of Efficient Electricity Price) is an e-bidding platform for power purchase by DISCOMs.

¹⁹ EESL was the implementing agency for the Unnat Jyoti by Affordable LEDs for All (UJALA) programme launched in January 2015. See the UJALA dashboard for more information: http://www.ujala.gov.in/

²⁰ India exported 5798 MUs of electricity to Nepal, Bangladesh and Myanmar in 2017.

²¹ As per PFC’s Annual Report 2016-17, as of March 31, 2017, 72% of its disbursements are with the state government sector and 58% are with the generation sector. As per REC’s website, on as of November 13, 2017, 75% of its outstanding loans are with the state government sector, 51% of its loans are for the transmission and distribution sector, and 47% are for generation projects.

²² Mukherjee 2014 World Bank report on private participation in Indian power sector, please see: https://openknowledge.worldbank.org/handle/10986/20410?hootPostID=669ad75a0fbadc905f3930aad2095024&locale-attribute=es

²³ CAG report on BHEL Report no. 26 of 2013, available at: https://cag.gov.in/content/report-no-26-2013-performance-audit-expansion-and-utilization-power-equipment-manufacturing

²⁴ http://www.thehindubusinessline.com/opinion/china-holds-key-to-indias-energy-future/article7271640.ece

²⁵ http://www.livemint.com/Industry/Od63lI7qolyDCncKm76eiO/Chinese-solar-module-firms-reneging-on-India-contracts.html

²⁶ Thermal (gas, coal) generation, nuclear and large hydro projects require an environment clearance. Projects such as solar, wind and small hydro (<25 MW) do not.

²⁷ Some projects, such as category B2 projects, are exempt from the mandatory public consultation.

²⁸ The environment clearance and environment impact assessment processes are governed by the EIA Notification 2006, issued under the Environment Protection Act, 1986.

²⁹ The consent to establish and the consent to operate are required under the Air and Water (Prevention and Control of Pollution) Act, 1974 and the Air (Prevention and Control of Pollution) Act, 1981.

6 : Economic and financial concepts related to the electricity sector

The power sector is characterised by large financial investments which fructify only years later. The sector requires large upfront investments which create assets that have a long useful life, but with few alternative uses. Given these characteristics, it becomes very important to carefully evaluate the investments to be made to ensure that they are worthwhile.

This chapter provides an overview of tools that can be used to assess the appropriateness or the comparative advantage of different investment options. These include, metrics such as payback period, accounting rate of return, internal rate of return and so on. The chapter also introduces several concepts such as time value of money and discount rates and the role they play in various financial decisions. Later in the chapter, we look at the costs involved in the construction and operation of different segments of the power sector, namely generation, transmission and distribution.

6.1 Understanding some basic investment concepts

In this section, we cover the basic tools used to evaluate investment decisions. The discussion here is limited to understanding these basic concepts relevant to the power sector. In practice, several technological, ecological, social and political considerations also affect decision making in the sector. Tools used to compare investment options analyse the costs and benefits of the projects, and hence, a proper estimation and projection of costs and benefits is the first step in analysing investment options. Once this is done, various tools can be put to use to evaluate these options.

We will look at two types of tools: tools that do not consider time value of money and those that do. Value of money is not constant and changes with time, as people value money that they have at any point of time differently from the same amount that they may receive in future. This is because of its potential earning capacity. (See Box 6.1 for more information on Time Value of Money) Figure 6.1 provides an overview of the tools covered in this chapter. The tools that fall in the first category are comparatively easier to use and understand, while those in the latter category are more complex, but are also more widely used in making investment decisions. The tools given below can be applied easily to transmission and distribution projects, as well as renewable energy generation projects. However, an evaluation of conventional generating stations, i.e. those that require fuel to generate, would require a few additional concepts which will be discussed in later sections.

Figure 6.1: Tools introduced in this chapter

The purpose of this section is to familiarise the reader with the tools for financial analysis commonly encountered in the power sector. It must be stated that the tools and analysis covered here are used primarily to account for financial costs of the projects whereas in reality such infrastructure projects impose many more costs which are not properly accounted for or cannot be accounted for.

6.1.1 Simple methods (not taking time value of money into consideration)

Let us begin with an example. You are an executive in a distribution company. A new neighbourhood is being developed in your area of electricity supply. Apartments, houses, shops, schools and parks are being built and you anticipate an increase in demand from this neighbourhood. You decide to build a new substation in this area.¹ Let us assume that your costs are only the money you will spend in building the substation, while the benefits will be the increase in sales and the lower T&D losses. Usually, multiple options exist for such an investment (for example, substations can have different designs and use different technologies) and you are faced with two design options as shown in Table 6.1. The first design option, Design A, costs Rs 100 crore and the annual benefit to the utility from increased sales and reduced losses is Rs 25 crore. The second design option, Design B, is available for Rs 150 crore, but gives an annual benefit of Rs 36 crore. Which design option should you choose?

Table 6.1: Design options for consideration

Parameters

Design A

Design B

Cost of the substation

(Rs crore)

100

150

Annual benefit (increase in sales, reduction in T&D loss) (Rs crore)

25

36

The choice between Design A and B should be made based on which option is more economical. The simplest method to compare such options is to calculate the ‘payback period’ of the investment.

Payback Period

The Payback Period is the period within which the initial investment is recovered. The simple division of investment by annual benefits gives us the payback period in years. Thus, the payback period for Design A is 4 years (=100/25) and that for Design B is 4.17 years (=150/36) (See Table 6.2). Since, the payback period of Design A is lower, this method recommends choosing Design A. Generally companies tend to invest only if the payback period is less than three years. However, for infrastructure projects such as dams, roads and power plants, a payback period of 10 to 12 years is considered good.

Table 6.2: Payback period and life of the asset

This method is simple to use, but has many limitations. Consider that the life of the first substation is 7 years and that of the second is 13 years (see Table 6.3). Which one should you choose? The payback period method does not take the life of the asset into account. It also does not take the benefits after the payback period into account, and also ignores the time value of money (explained in later sections).

Accounting Rate of Return

The ‘Accounting Rate of Return (ARR)’ method, also called the average rate of return method, overcomes one of the limitations with payback period. It takes into account the benefits from the investment over the entire life of the asset (in this case the substation). The accounting rate of return is calculated by dividing the average annual profit by the initial value of the asset. Profit calculation depends on the accounting framework. In this example we have calculated profit as savings less depreciation. Thus,

Depreciation, as we shall see later, represents the reduction in the value of the asset due to ageing and use. In our example, we assume that value of the asset depreciates to zero at the end of its life. Thus, in our example,

This depreciation will be subtracted from the annual benefits to arrive at annual profits, and then the accounting rate of return will be calculated. As can be seen from Table 6.3, as per this method, Design B is better than Design A, since it has a higher accounting rate of return.

Table 6.3: Accounting Rate of Return

6.1.2 Taking the value of time into consideration

The major limitation in both the above methods is that they do not account for the time value of money. As we shall see, there are a number of methods that do take into account the time value of money, such as the Net Present Value, the Benefit Cost Ratio and the Internal Rate of Return. Let us first understand the time value of money. Box 6.1 explains this concept and the associated concepts of discount rate and present value. Those familiar with these concepts can move on to the first method for comparing investment decisions using the concept of time value - the Net Present Value.

Box 6.1: Time Value of Money

At the heart of the concept of the ‘time value of money’ is the idea that money now is better than money in the future. Thus, a rational person would prefer receiving Rs 100 today than receiving it (the same Rs 100) in the future. This is because money has the potential to grow in value, i.e. you can do things with Rs 100 today that can give you more benefit than what you can do with Rs 100 in the future.

Consider an example. Say a person has a choice between receiving Rs 100 now or Rs 100 after two years. Now assume that the rate of compound interest on deposits in banks is 5%. If the person chooses to take Rs 100 now, she could deposit this in a bank. In two years, her Rs 100 would be worth Rs 110.25 (=100 x (1+5%)2) (See future value formula below). So it makes more sense for her to receive Rs 100 now than after two years.

Future Value=Present Value x (1+interest rate)t, where t is the number of years.

While how much more a person values money today over money in the future will differ between people, this idea is captured in a factor called the ‘discount rate’. The discount rate is, in many ways, similar to the bank interest rate. We can use the bank interest rate here as the ‘discount rate’ to calculate the ‘present value’ of the future payment. We get the formula for present value by moving parts of the future value formula around (See present value formula below). Thus, considering our previous example, choosing between Rs 100 now and Rs 100 two year later, we can calculate the present value of the future payment. We see that present value is only Rs 90.70 today (=100/(1+5%)2), i.e. accepting Rs 100 in two year is like accepting Rs 90.70 today.

Such lowering of the value of future cash payments (in this case the future Rs 100) is known as ‘discounting future cash flows’. Calculating the present value is a useful method in comparing investments that offer returns at different times. To understand this, consider another example. Say a person has a choice between Rs 100 today or Rs 150 in four years. Which should she choose? Taking the same discount rate of 5%, we find that the present value of Rs 150 in four years is Rs 123.4. In this case, the person is better off accepting Rs 150 after four years.

Discount rates in practice: The discount rate stands for the opportunity cost of capital, i.e. it represents the rate of return that the same amount of money will fetch if invested in an alternative (next best) scheme. Thus, the discount rate will differ based on who is making the decision, in what kind of industry and when. For utilities, the discount rate is usually taken as the utility’s weighted average cost of capital (WACC). Consumers usually demand a high rate of return, and hence, they have a high discount rate when making a decision to purchase an appliance, etc. The interest rates and the rate of inflation both have an impact on the discount rate. The higher the discount rate, the lower the present value of the future cash flow. The discount rate also depends on the inflation rate in the country where the firm is located (or in the case of a multinational, all the countries where it operates). Some people have argued that projects that serve the public good and are long-lived (even if built by a private company) should be analysed using a much lower discount rate, also called the social discount rate. This is important, since at higher discount rates, the benefits over a longer time frame (say 40-60 years), essentially count for practically nothing when valued in today’s terms using that high discount rate. Usually, Indian businesses use a discount rate of 12% to 15%, while governments use a discount rate of 6% to 8%. In our examples, we have assumed a discount rate of 12%.

Real and nominal prices: When comparing prices of any commodities today, we only have to see their price today or their ‘current price’. However, when we want to compare prices for a past or future date, one needs to adjust prices to account for inflation. In this context, the ‘nominal’ price is the price which has not been adjusted for inflation, while ‘real’ price is the inflation-adjusted price, i.e. the price after removing the effect of general inflation (overall price increase). One can use either price, but it is important to specify it and maintain consistency for comparison.

Net Present Value (NPV)

The ‘Net Present Value (NPV)’ method addresses both the limitations of the Payback Period method, i.e. it accounts for the benefits over the life of the project and accounts for the time value of money. NPV is equal to the sum of the present value of all cash flows of the project less the initial investment. The ‘present value’ of the cash flow is determined using the discount rate. Income is a positive cash flow, while investment is a negative cash flow. Hence, if the present value of cash inflows is more than the present value of the investment or cash outflows, it leads to a positive NPV.

In our example, let us assume that Design A provides an annual benefit (cash inflow) of Rs 25 crore for the entire duration of its life (7 years), while Design B provides an annual benefit of Rs 36 crore for 13 years. Investment is a negative cash flow, but since it is incurred in the present it is already in present value. There are no other future cash outflows. The calculation of the NPV is straightforward using the Present Value (PV) formula in software such as MS Excel and then subtracting the initial investment from it.² The present value of all future cash inflows is Rs 114 crore for Design A and Rs 231 crore for Design B. We get NPV by subtracting the initial investment from the present value, giving us Rs 14 crore for Design A and Rs 81 crore for Design B as seen in Table 6.4.

Table 6.4: Net Present Value (NPV)

In NPV analysis, we accept a project if its NPV is positive. This is obvious since a negative NPV means that the value of our future payments today (the present value) is less than the money in hand. If we are comparing two projects (as in our example) and if both projects have positive NPVs, then the project with the higher NPV is accepted. In our example, the NPV analysis indicates that both options are worth investing in, since both have positive NPVs. However, the second option is better since its NPV is higher, i.e. Design B is a better investment option.

Decision rule: Reject projects with negative NPVs, and accept if positive. The larger the positive NPV, the more the benefit to the company, so if faced with two positive NPVs pick the larger positive NPV.

It is important to highlight here how sensitive the NPV is to the discount rate. From Table 6.4, it can be seen that if the discount rate is taken as 20%, the NPV for Design A actually turns negative. Thus, if the discount rate increases, the NPV decreases. In addition, while in our example, we have the same cash flow every year, projects may have different cash flows every year. If more cash is received in the early years, the NPV increases. So, when evaluating a project, one has to be careful since huge capital expenditure and delayed income is a situation quite common in the power sector. In addition, the NPV is an absolute number and does not consider the size of the project. The NPV of a small project is not directly comparable to the NPV of a large project. The next two methods account for this factor as well.

Benefit-Cost Ratio (BCR)

In the NPV method, we saw that after accounting for the life of the equipment and the time value of money, Design B has a higher NPV. However, we also need to consider the higher costs of Design B while making the comparison. This is fairly easy once the future benefits have been converted into their present values (i.e. to the year when the investment is made) and can be juxtaposed with the initial investment. We can now calculate the benefit per rupee invested, by simply dividing the Present Value of the benefits by the Present Value of the costs. This is called the Benefit-Cost Ratio (BCR) or the Profitability Index (PI), and can be seen in Table 6.5.

Benefit Cost Ratio= Present Value of Benefits/ Pesent Value of Costs

Table 6.5: Benefit - Cost Ratio

Decision Rule: The BCR of any investment should be greater than 1 for it to qualify as an economically viable investment.

In our example, the Present Value of benefits is Rs 114 crore for Design A and Rs 231 crore for Design B. Since our cost is just the initial investment, it is already in present value. Thus, the BCR for Design A is 1.14 while that for Design B is 1.54. Although both the designs are profitable in our example, the benefit per rupee invested is higher for Design B. Thus, the BCR method recommends choosing Design B.

Internal Rate of Return (IRR)

Another common method to compare different investment options is called the ‘Internal Rate of Return (IRR)’. IRR is in essence the rate at which the investment breaks even, i.e. the discount rate at which the present value of the future cash flows equals the investment. Technically, the IRR is described as the discount rate at which the NPV of the cash flow (inflow and outflow) becomes zero. Put differently, it is the rate at which the PV of cash inflows equals our initial capital expenditure. Thus, in calculating the IRR, we are looking for the discount rate at which the present value of future income is exactly equal to the investment.

If NPV=0, then the discount rate=IRR

If PV=initial investment, then the discount rate=IRR

Given the formula for NPV, calculating the IRR is an iterative process and needs a guess estimate to start with. MS Excel and other software have inbuilt IRR calculating programmes. One has to arrange the annual cash flows in a sequence, with the initial investment with a negative sign (to represent cash outflow) and benefits with a positive sign (to represent cash inflow). Then the worksheet function called IRR can calculate the value.

Let us look at the two investment options in our example from the point of view of a finance executive of the company. In evaluating the two investment options, she needs to know that in Design A, she has to pay Rs 100 crore today and will get Rs 25 crore back each year for the next seven years. Similarly, for Design B, she has to make an initial investment of Rs 150 crore and would get back Rs 36 crore each year for the next 13 years. The IRR calculations can be seen in Table 6.6. Given that the IRR for Design B is higher, the finance executive will definitely choose Design B over Design A.

Decision rule for IRR: The higher the IRR, the more profitable the investment. Normally, a project is accepted using the IRR method if the IRR is higher than or equal to the ‘hurdle rate’. This is the minimum rate required from the investment and is decided by the finance department of the company. The hurdle rate is also called the ‘cut-off rate’ or the ‘required rate of return’. Generally, the cost of raising capital is taken as the hurdle rate.

In our example, let us assume that the hurdle rate is 18%. In that case, the finance officer will choose Design B and reject Design A.

Table 6.6: Internal Rate of Return

Parameters

Design A

Design B

Cost of the substation

(Rs crore)

100

150

Annual benefit (increase in sales, reduction in T&D loss)

(Rs crore)

25

36

Payback Period (in years)

4

4.17

Life of the substation (in years)

7

13

Accounting Rate of

Return (%)

10.7%

16.3%

Discount Rate (%)

12%

12%

Present Value (Rs crore)

114

231

Net Present Value (NPV)

(Rs crore)

14

81

Benefit-Cost Ratio (BCR)

1.14

1.54

Hurdle rate (minimum rate

of return required) %

18%

Internal Rate of Return

(IRR) (%)

16.3%

22.2%

NPV and IRR

Both NPV and IRR are similar but use different variables in their calculations. The NPV method determines the present value of future cash flow for a particular discount rate, while the IRR method determines the discount rate at which the NPV equals zero. While the NPV gives an absolute value (in Rs), the IRR gives a rate of return (in %).

However one must be careful using IRR alone, especially if one is basing decisions on the highest IRR. To understand this concept, consider the following example. We take our two designs, but instead of them giving constant returns, let us assume they give returns as shown in Table 6.7.

Table 6.7: Annual savings from Design A and Design B (in Rs crore)

Year

Design A

Design B

0

-100

-150

1

10

5

2

10

5

3

10

10

4

25

10

5

25

10

6

25

10

7

25

15

8

15

9

15

10

20

11

30

12

36

13

36

IRR

5.87%

4.24%

Note: Year 0 is the year that the investment is made, i.e. money is spent on buying and installing the transformers.

From the table, we see that in Design A, cash inflows start low, at Rs 10 crore per year and then finally increase to a maximum of Rs 25 crore starting from year 4 onwards. In Design B, cash inflows start low, at Rs 5 crore per year and steadily increase to 10, 15, 20 culminating in the maximum of Rs 36 crore for the last two years. The manner in which returns are expected changes the IRR, and the new IRR for the projects is 5.87% and 4.24% for Design A and Design B respectively.

Now, if we were using only IRR, we would be tempted to choose Design A since it has the higher IRR. However, let us calculate the NPV of these two designs. We know that the NPV is sensitive to the discount rate. Let us calculate the NPV for three different discount rates: 2%, 3.3% and 4%. The NPVs for the projects are given in Table 6.8.

We see that at 2% discount rate, the NPV of Design B is higher than that of Design A, i.e. Design B is preferable to Design A. At 3.3%, the NPVs for Designs A and B are the same so we are indifferent to whether we choose A or B. At 4%, Design A becomes preferable. Let us plot the NPV for these two designs for discount rates from 0% to 8% as seen in Figure 6.2.

Figure 6.2: NPV of Design A and B at different discount rates

Source: Prayas (Energy Group)

Table 6.8: Net Present Value (in Rs crore) at discount rates of 2%, 3.3% and 4%

Discount Rate

Design A

Design B

2%

19

31

3.3%

12

12

4%

8

3

What does Figure 6.2 tell us? It tells us that for the same IRR, the NPV can be very different given the discount rate. It also shows that the decision to prefer one project over another is dependent on the cash flow of the project and the discount rate. From this figure we can also see that if the discount rate was more than 6%, neither of the designs would be worth investing in.

Hence it is advisable not to use IRR exclusively to determine the choice of investments. This should be coupled with other metrics like NPV, especially when projects have differing timelines. Further, IRR can be calculated before or after tax and for the entire project or only for the equity investment. It is important to use appropriate type of IRR depending on what one is evaluating.

The concept of present value is also used to calculate the cost of conserved energy, which is a popular method of deciding between investing in one kind of appliance over another, especially in terms of energy efficiency. This method is briefly discussed in Box 6.2.

Box 6.2: Cost of Conserved Energy

Let us assume that you are looking to purchase a new fan. You have two options: you can purchase a super efficient fan that consumes 35 W and costs Rs 1,200, or an unlabelled fan that consumes 70 W and costs Rs 700. Both fans have a lifespan of 15 years. How should you go about making this decision?

We can see that the super efficient fan costs Rs 500 more than the unlabelled one, but saves 63 units of electricity per year assuming 1800 hours of operation for the fan per year. The cost of conserved energy can be calculated by (1) annualising the incremental cost of purchasing the more energy efficient appliance (in this case, Rs 500) over the life of the appliance using an appropriate discount rate, and (2) dividing this annualised cost by the energy saved per year. Let us calculate the cost of conserved energy for our example.

Assuming a discount rate of 12%, we get an annualised incremental cost of Rs 73.41 per year.³ Thus, the annual savings from buying a super efficient fan is 63 units for a total annual cost of Rs 73.41, which gives us our Cost of Conserved Energy of Rs 1.16 per kWh. If we were to buy the unlabelled fan, we would be consuming 63 units more. The lowest slab for consumer tariff in India is around Rs 1.5 per kWh. As a consumer we would compare the Cost of Conserved Energy versus the cost of electricity. Since the Cost of Conserved Energy at Rs 1.16 per kWh is less than cost of electricity at Rs 1.5 per kWh, buying the super efficient fan makes more economic sense for the consumer.

As a rule, if the Cost of Conserved Energy is lower than the cost at which that energy is being produced, it makes economic sense to invest in that energy saving technology (in this case, purchasing the energy efficient fan). It must be kept in mind here that the energy saved will be different at the consumer’s end than, say, the electricity distribution company’s end. Thus, if an electricity distribution company is considering investing in energy saving technology, it would also have to account for the T&D losses and then compare the cost of purchasing that energy vs the Cost of Conserved Energy in order to make a decision. As in the case of present value, the cost of conserved energy is also sensitive to the discount rate and hence, it is important to have an accurate estimation of the discount rate.

6.1.3 Economics of the power project with a bank loan

As we know, power projects are capital intensive, and no company sets up the project with its own money alone. Power sector projects are funded through a mix of equity (i.e. the money that the company or promoter puts in) and debt (i.e. the loan taken from the bank or other institutions). Let us look at Design B from our example again. Let us assume that there are two ways in which this project can be funded: The first is what we have seen so far and involves the project proponent (in this case the distribution company looking to build the substation) putting in all the money. The second involves the project proponent taking a loan for part of the cost of building the substation. We shall assume that the company is putting in 25% of the money and the bank is giving a loan for the remaining 75%. Table 6.9 provides details of the loan.

Given the cost of the substation, if the distribution company is taking a loan for 75% of the cost, its loan amount would be Rs 112.5 crore. Let us assume that the interest rate on the bank loan is 10% and the repayment period is 8 years. Using this information, one can calculate the annual repayment of loan (interest + principal). For this purpose we use the PMT function in MS Excel. The annual loan repayment works out to Rs 21 crore. This repayment is a cash ‘outflow’ for the project. Now, the equity investment is only Rs 37.5 crore (i.e. Rs 150 - Rs 112.5). Till the repayment of the loan, the substation will provide Rs 14.9 crore in benefit (i.e. Rs 36 - Rs 21.1). So the utility makes Rs 14.9 crore in benefits for the first eight years, and then Rs 36 crore for the remaining five years after the loan is fully repaid. This changes the economics of the investment decision.

From our example, we see that the BC ratio and the IRR are much higher with the bank loan than without it. Thus, the bank loan changes the profitability of the investment, and in our example, the loan substantially improves the profitability of Design B. This happens because in our example the benefits remain unaffected. While our original IRR was 22.2%, the bank loan rate is only 10%. Thus, a bank loan reduces the equity, but given the bank loan rate, this reduced equity actually earns a higher return. However, the type of loan is an important parameter in changing the profitability for the better. If for example the bank loan rate were 25%, then the new IRR would drop to 18.5%, i.e. lower than the old IRR of 22.2%, making the bank loan option unattractive. Improving profitability with a bank loan requires a low interest rate and a longer repayment period.

Table 6.9: Economics of Design B with and without a loan

Parameters

Design B (without loan)

Design B (with loan)

Cost of the substation (Rs crore)

150

Of which:

Debt

-

112.5 (75%)

Equity

150

37.5 (25%)

Interest rate on debt (loan from bank) (%)

-

10%

Repayment period of debt (in years)

-

8

Annual repayment of loan plus interest

(Rs crore)

-

21

Annual benefit (increase in sales, reduction in T&D loss) (Rs crore)

36

Life of the substation

(in years)

13

Average Annual Benefit (Rs crore)

36

14.9 for the first eight years,

36 from the ninth year

Discount Rate (%)

12%

Payback Period

(in years)

4.17

2.51

Benefit-Cost Ratio (BCR)

1.54

3.37

Internal Rate of Return (IRR) (%)

22.2%

42.1%

6.2 Making an investment decision to build a new power plant

6.2.1 Factors affecting the decision to build a plant

Multiple factors affect the decision to build a power plant, and the plant, its characteristics and its operation in turn are dependent on multiple factors. An increase in electricity demand (actual or anticipated) could lead a generation company to decide to build a new generating station. As we have seen in Chapter 3, the power system also needs different kinds of generating plants. Some are required to operate at full load all the time (‘base load plants’), while others are expected to operate only during periods of high demand (‘peak load plants’). These plants differ in many aspects, such as the cost of generation, technology, the capability to quickly change generation levels, type of fuel, etc. A generation company would thus need to decide on the type of plant, technology and fuel for its generating plant.

The location of the generating plant is also of critical importance since it impacts costs. For instance, building a generating plant in the heart of Mumbai would be much more expensive than building the same plant in a semi-urban or rural region elsewhere in Maharashtra. This is due to the higher land cost as well as other costs such as the cost of construction and labour. Property taxes are also much higher in Mumbai. Such higher capital costs and sometimes even higher fuel costs (as a result of higher transportation costs) as well as stricter environmental restrictions or constraints such as water availability in certain areas may demand an investigation into alternative locations for the generating plant. This could also involve building the plant in a remote location, and building sufficient transmission capacity to bring the electricity to the load centres (like the urban areas or industrial belts). In terms of the cost of fuel, locations near the coalmines or near ports (for imported fuel based plants) are more economical. In India, this is a highly contested topic with a large number of power plants clustered in a few coal rich pockets creating many environmental and social challenges.

In addition to technology and location, there are several other variables that should also be considered before making a decision. For example, expected changes in fuel cost over time may be different for different types of fuels and hence, would affect the economics of the plant. Accounting for all these factors is a challenging task.

Finally, it would be naïve to assume that decisions to build plants are driven solely by power system and economic considerations. Political and social considerations and ground realities also play a major role in locating power plants. For example, when asked why it decided to construct Parli Unit 8 given its locational disadvantage, the Maharashtra State Generation Company Limited (MSPGCL) responded as follows: ‘MSPGCL has selected the locations for the development of power generation like Vidarbha, Marathwada, Khandesh, Konkan and Northern Maharashtra regions in line with the GoM (Government of Maharashtra) objective of development of all regions. Although the input costs for some of the locations may be higher, the stability of the power grid was considered for implementation of the projects.’⁴

Thus, the world over ‘decisions about whether or where to build power projects have always been influenced by a complex web of factors in which technical and geographic considerations meet cultural, commercial and political pressures to create the abstract mosaic of power plants that dot the world’.⁵

6.2.2 Economics of conventional generation plants

The economics of conventional generating plants (coal, gas, and nuclear) are different from that of distribution or transmission projects. This is because most costs in a distribution or transmission project or a renewable energy based plant, are incurred upfront. Thus, the costs are mostly fixed in nature, and do not vary by how much the asset gets used. A conventional generation plant too has fixed costs, but it also requires fuel to run. This cost of fuel is separate from the fixed cost and forms a sizeable portion of the total cost of conventional generation projects (coal and gas). The fuel cost is not fixed but is proportional to plant usage and is called ‘variable cost’. The fixed cost and the variable cost together make the ‘total cost’ of the generation project. See Box 6.3 to understand the interplay between fixed and variable costs.

Box 6.3: Running a conventional power plant

Suppose you have just bought a car. You took out a loan from your bank for it and you will have to pay back the loan through EMIs (Equated Monthly Instalments) for 10 years. In addition, you will need to fill petrol or diesel (or charge the car, if you bought an electric one) and this too will entail costs. The amount of fuel you use in your car and consequently the amount you spend on fuel will depend on how much you drive around, and could vary from month to month. However, your EMI to your bank will not vary on a monthly basis. It will have to be paid whether you drive your car or not.

Similarly, in a generation plant, the fixed cost comprises of principal and interest payments that the generation company has to make to banks for the loans availed. In fact, the Power Purchase Agreement (PPA) contracts are designed such that the distribution company has to pay the fixed charges (which pay for the fixed cost) irrespective of how much electricity it asks the generating station to produce. The variable charges on the other hand are paid in proportion to the actual electricity generation that is purchased by the distribution company.

The existence of variable costs changes the economics of conventional generating plants. In this section, we will see the costs associated with a generating plant, the variation in costs due to usage and how the changed economics of the project is incorporated into tools to make investment decisions - whether or not to build a certain generating plant.

We begin by looking at the costs of different types of generating plants. We then move on to discussing two important tools in evaluating the alternative generation options - the life-cycle costs and the levelised tariff.

Three different kinds of plants

To understand the evaluation of alternative generation options, let us take the example of three generating plants - A, B and C. We assume that they are each of 1000 MW capacity, but there are design and fuel differences between them. Their details are given in Table 6.10.

Table 6.10: Comparing annual costs of generating plants

In our example, we find that while Plant C is the cheapest to build (it has the lowest total project cost), its fuel cost per kWh (and annual increase in fuel cost) is the highest. Plant A on the other hand is the most expensive (its total project cost is more than double that of Project C), but its fuel cost is much lower. Plant B lies somewhere in between these two plants.

Let us first look at the various costs associated with our generating plants. We begin by calculating the fixed cost of the project. These are the costs that do not vary with the usage of the plant. In our example, the employee expenses, all loan repayments, and return on equity are fixed costs. The annual employee expenses for each of the plants are given in row 7; these expenses (and some others) form part of the operation and maintenance expenses of the generating plant and are given in row 11. We assume that these will not change over the life of the project (in reality, of course, they would increase, usually in tandem with inflation). We use the PMT function in MS Excel to calculate the repayment of loan and interest payment (row 12) by specifying vales for the loan amount, period of loan, and rate of interest.⁶ Thus, the total fixed costs for our plants are Rs 1432 crore, Rs 988 crore and Rs 692 crore respectively for plants A, B, and C (row 13) for the first year.

The variable costs (which vary with plant usage) include the cost of fuel, the cost of transporting fuel to the generating station, and taxes and duties on it. In our stylised example, we assume that the cost of fuel includes all these other costs. For the variable costs we need to understand the fuel use as well as the generation of electricity. Now, the electricity generated as well as the fuel cost is a function of the Plant Load Factor (PLF or capacity utilisation, see Chapter 3) of the plant. In our example, we assume that all three plants are running at 70% PLF (row 10). This gives us the units of gross electricity generated (row 14). We also have the cost of fuel per unit of electricity generated from the plant (row 8). The generation and the cost of fuel give us the total variable cost for our three plants for the first year (row 15): Rs 613 crore for Plant A, Rs 920 crore for Plant B, and Rs 920 crore for Plant C.

From the addition of the fixed and variable costs, we get the total cost of each of our plants for the first year (row 16). Thus, the total cost for Plant A is Rs 2045 crore, for Plant B is Rs 1908 crore and for Plant C is Rs 1612 crore.

Now we will use this example to learn some important concepts regarding generating plants.

Impact of usage on plant economics

We begin to understand investment in generation projects by understanding the interplay between the fixed and variable costs of the projects. The consumers and even the planners are interested in understanding the cost of power from a power plant. To calculate this, we need to divide the total cost by the units generated. We have calculated this value for the plants in our example (rows 17, 18 and 19).

As mentioned above, the fuel cost is a function of the electricity units generated, indicated by the PLF. To understand how an increase in generation (higher PLF) impacts costs, let us consider Plant B. We have calculated the units of electricity generated, its variable cost and total cost at different values of PLF in Table 6.11.

Table 6.11: Linkage between PLF and cost of power generation

As we can see, as the PLF increases, the total cost increases as a result of the increase in variable (fuel) cost. But the total cost increases at a slower pace than the amount of electricity generated since the fixed cost remains unchanged. Due to this, the per-unit cost of generation from the plants comes down with an increase in the PLF. Since coal based plants are capable of running at higher PLFs, often the per-unit cost is projected under the assumption of PLF at 80% or 85% which makes the per unit cost look more attractive in comparison to a more realistic PLF of say, 65-70%.

Life cycle costs (to evaluate trade-offs between capital and fuel costs)

For our three plants, the fixed cost consists of the loan and the employee expenses. We have assumed that the loan repayment period for all three plants is 10 years, after which the loan and interest payments will become zero. We have also assumed that there will be no increase in employee costs, so that this cost will remain constant for the entire life of the plant. Thus, for each of the plants, the fixed cost shall remain constant for the period of the loan repayment (10 years), but after the loan repayment (year 11 onwards) shall consist only of the employee expenses.

In our example, we assumed that in the future the fuel cost of the plants is expected to increase at different rates. Rows 8 and 9 give the price of fuel and the annual increase in fuel price. It is possible to calculate the fuel price increase each year given the price during the first year and expected yearly increase. The calculated fuel price is added to the fixed cost for each year to get the total cost. From year 11, the total cost will fall substantially since the loan would have been repaid. Figure 6.3 shows this trend for our plants in a graph.

Figure 6.3: Changing total costs of the three generation plants

Source: Prayas (Energy Group)

If we were to take the average cost over the 20 year period for all three plants, the average cost is highest for Plant B and lowest for Plant A, such that B>C>A. In fact, the average cost of plants B and C is higher than plant A by 24% and 23% respectively. But knowing that money has time value, we cannot take the simple average as the measure for comparison. For example, Plant A has a higher cost in the initial years, but becomes economical in the later years. Hence, for comparison, it is essential to account for the time value of money.

The concept of Life Cycle Cost (LCC) is used for such comparisons, where projects have varying costs over time. LCC is the present value of all costs in the life of a plant. It is thus equal to the sum of the PV of annual costs, and initial cost (if any). LCC can be used to compare alternatives like those in our example that have the same life periods.

As always with calculating present value, deciding on the discount rate is critical, especially when the costs are changing from one year to the next with higher costs in the initial years. In Table 6.12 the LCC⁷ for our plants using different discount rates is shown. The figures for lowest cost option are highlighted.

Table 6.12: Discount rate and life cycle costs (Rs crore)

As can be seen, while Plant A is the most economical option at a discount rates up to 12%, Plant C becomes more economical as the discount rate increases. At 25% discount rate, Plant A is the most expensive, with both Plant B and C having lower LCCs. Clearly, the discount rates can be a crucial input parameter in such cost comparisons, and we have to be extremely careful in examining what discount rate is used. The higher the discount rate used, the lower is the weight given to future costs.

Levelised cost of energy (to compare plants with different life)

The concept of life-cycle costs has two limitations: (a) it does not give us a value of representative tariff (in Rs per unit) that remains constant throughout the life of the plant and (b) it cannot be used to compare options that have different life periods. The concept of ‘Levelised Cost’ is used to overcome both these limitations. This is also called annualising the life cycle costs. The levelised cost of energy (LCOE) is the representative per unit cost that remains constant over the life of the project. It is the tariff at which the power plant can be considered as an economically viable option. It is a useful tool because it combines both the fixed cost and the variable cost, and provides a single measure to compare across projects.

Levelised Cost is calculated in three steps: (1) the ‘Present Value’ of all costs is calculated by discounting all costs to the base year and then calculating their sum. This gives the ‘Lifetime Costs’ (in rupees); (2) the present value of all energy generated is similarly calculated, by discounting the quantity of energy produced over the life of the project (to the same base year) and then calculating its sum.⁸ This gives the ‘Lifetime Energy Output’ (in units of electricity); (3) the Lifetime Costs are divided by the Lifetime Energy Output to get the Levelised Cost (in Rs per kWh).

Let us calculate the levelised cost for our three power plants from the previous example, using a discount rate of 12%. These values are given in Table 6.13.

Table 6.13: Levelised Cost for the plants

If we take Plant B, we see that its lowest actual cost is in the 11th year and is Rs 2.18 per kWh, while its highest is Rs 3.57 per kWh in the 10th year, but its levelised cost is Rs 3.07 per unit. The total cost per unit for each year and the levelised cost for Plant B are shown in Figure 6.4.

Figure 6.4: Total cost and levelised cost for Plant B

Source: Prayas (Energy Group)

The levelised cost is taken as the representative per unit cost of that option. In our example, Plant C has the lowest levelised cost of the three options.

Once we have our levelised costs, we can now use them to make decisions about whether or not to build a plant and if so, then which one. For this, we compare the levelised cost with the tariff or prices for electricity generation in the market. The simple rule is: if the market price is higher than the levelised cost then the project is profitable. In our example, let us assume that the prevailing generation tariff is Rs 3.0 per unit, then building Plant A or Plant C makes sense; however, if the price were Rs 2.5 per unit, then it does not make sense to build any of the plants.

In the above example, the plant output can also be changing over time. Thus, the levelised cost can be used to compare plants that have different or changing generation. Levelised cost is a highly versatile tool to compare costs across plants, even plants with different economic lives. Typically, however, it is used to compare plants with the same economic life. It is important to ensure that the plants being compared have the same pattern of generation, i.e. the plants being compared are all base load or peak load. This is important since different generation technologies allow for different flexibility and hence using only LCOE for comparison could be misleading if plants are meant for specific system requirements.

It is essential to take some precautions while calculating the levelised cost. The use of the same discount rate and the use of the same base year for all the plants are the basic precautions. As we have seen earlier, the choice of discount rate can make a lot of difference. Low discount rates favour low variable cost projects like hydro plants, while high discount rates prefer higher variable cost and lower fixed cost options. It should also be remembered that the future tariff is projected using some assumptions about key parameters, such as fuel cost increase and generation (PLF) in the future years. If these assumptions prove to be incorrect, naturally the levelised cost would not be an accurate representation of the true cost. Thus, the levelised cost is not representative of the real future tariff but only a proxy for it.

6.3 Financing power projects

Till the early 1990s, investment in the power sector was largely financed through government loans. The power sector was state owned and the government loans came either as budgetary support or as special purpose loans, such as for rural electrification and power plant renovation. The budgetary support came from the state and central government budgets. But the revenue generated from sale of power did not fully suffice to repay the loans and some SEBs did not even pay interest on these loans. The government continued to provide budgetary support even while running a deficit budget (i.e. the government expenditure exceeded its budget).

By the early 1990s, India was facing a foreign exchange crisis, and the state and central budget deficits had also increased substantially. An IMF loan was sought, which came with conditions, one of which was that the government must reduce its budgetary deficits. The SEBs were not in a good financial situation and no commercial lending agency was willing to lend them money. As a result, the capital availability for the power sector reduced dramatically. To address this problem, the government decided to invite the private sector initially to the electricity generation sector. This took the form of Independent Power Producers (IPPs). The SEBs were expected to sign long-term contracts with these generators. The private generators were expected to raise money from the market.

6.3.1 Project Finance

As mentioned, infrastructure projects are financed through a combination of equity and loan (which is usually around 70%-80% of the project cost). In most non-infrastructure projects, like a car factory, the owner takes a loan on the strength of the balance sheet (which has assets and liabilities of his other businesses). If the car factory is unsuccessful, the owner loses money; in addition, the assets of his other businesses are also at risk since they can be hypothecated by the bank against the loan for the car factory. This mode of financing is called ‘corporate finance’ or ‘on-balance sheet finance’.

Infrastructure projects such as power plants need very large capital, and few promoters are willing to risk their on-going businesses for these projects. Moreover, in India, the SEBs were the sole buyers of the power and they were making losses. Hence, the logic of the owner taking a business risk through such ‘corporate finance’ did not apply to power projects.

‘Project finance’ helped mitigate these risks, where the loan is not given to the project promoter on the basis of its balance sheet, but instead on the basis of the cash flow expected from the project. Thus, it is also called ‘off-balance sheet financing’. Typically in project finance, the loan is given to a Special Purpose Vehicle (SPV), which is an entity with no business on its books created just for the execution of the project. The revenue/cash flow for payments will ensue once the project starts operation. For power generation project this means that the revenue will start coming in once the project is constructed and has agreements to (a) get fuel, if it runs on fuel, and (b) has a power purchase agreement, so that there is a long term certainty someone buying the power it can produce. Under project finance, if the project fails and the SPV defaults on loans, the banks can only hypothecate the project in question but will have no recourse to the other businesses and assets of the promoter. This type of ‘non-recourse’ financing shifts risk onto the lending institutions which are then required to perform extensive due diligence to ensure that the project is viable and can ensure repayment.

6.3.2 Lending by financial institutions

In India, credit decisions are not regulated, i.e. banks frame their own lending policies in accordance with the regulatory norms and guidelines, and take lending decisions based on their own internal assessment of the viability of the project and their lending policies. For example, the internal lending guidelines of the Power Finance Corporation (PFC) and Rural Electrification Corporation (REC), both significant lenders to power sector projects, state that the capability of the project promoter to build the project based on past experience in similar projects should be considered, as should the promoter’s potential for bringing in equity that is required for the project. In addition, the viability of the project needs to be assessed since this will determine the repayment of the interest and loan. This involved ensuring that the Debt Service Coverage Ratio (DSCR)⁹ is at least 1, and that the Internal Rate of Return (IRR, from earlier in the chapter) is higher than the hurdle rate.

Usually for power projects in India, the lending is done not by individual banks but by a consortium of banks, wherein the ‘lead bank’ conducts an appraisal of the project and then circulates the appraisal report to other interested banks. Individual banks then vet the appraisal report and can also conduct the project viability assessment independently before sanctioning the loan. Lending institutions also appoint a Lenders Independent Engineer to provide opinion on the technical and economic aspects of the project under consideration for a loan. See box 6.4 for more details regarding the lending pattern that has been observed so far and its implications for the sector.

EXIM Banks or export promotion banks are public agencies of a country, which give loans for different projects in other (usually developing) countries. For example, the Japan Bank of International Cooperation gave a loan to NTPC’s Kudgi Thermal Power Plant, while the Export-Import Bank of the United States had given a loan to Reliance’s Sasan Ultra Mega Power Project. EXIM banks demand that the borrowing country and its financial institutions should guarantee repayment of the loan. In most cases EXIM loans also come with conditions, usually requiring plants to purchase equipment from the lender country.

Box 6.4: Who is financing our thermal power projects?

As mentioned earlier, the power sector requires large investments and different kinds of lenders are approached for funds. These include national sources of finance, such as public sector banks (PSBs) like the State Bank of India and the Punjab National Bank, private sector banks (Pvt SBs) such as ICICI Bank, non-banking financial institutions (NBFIs), etc. These can also include international financial institutions (IFIs), such as the EXIM banks of other countries, and international development finance organisations such as the Asian Development Bank (ADB) and the World Bank. Setting up a power plant is also a de-licensed activity (Section 7 of E Act). Given the multiple sources of available finance and the de-licensing of the generation segment, it is important to understand where the funding for power projects is coming from.

The Centre for Financial Accountability (CFA)¹⁰ looked at 125 coal based generation projects of 1000 MW and above (57 public sector and 68 private) which had received the Terms of Reference or Environment Clearance from the Ministry of Environment and Forest between 2005 and 2015. They looked at the lenders for these projects (see Figure 6.5) and found the following:

A total of Rs 6.32 lakh crore had been given as loans to these projects; most of the financing (89%) came for national financial institutions, i.e. from national PSBs, national Pvt SBs and national NBFIs.

Among IFIs, China Development Bank was the most significant lender, with its loans almost three times more than the Japan Bank for International Cooperation, the second most significant lender. The US EXIM Bank and the Korea EXIM Bank were next in line. While China Development Bank was the biggest lender (in terms of the amount), it was the Royal Bank of Scotland which had loaned funds to the maximum number of projects (nine projects).

National NBFIs provided financing for more than half the capacity. Among NBFIs, the Power Finance Corporation (PFC) and Rural Electrification Corporation (REC) accounted for 94% of the financing from this category.

National PSBs provided the next most common source of funding, with State Bank of India, IDBI and the Punjab National Bank investing 62% among the public sector commercial banks.

National Pvt SBs remained small players, with the exception of ICICI, which alone accounted for 77% of the lending from this category.

Figure 6.5: Lending sources for 125 thermal projects that were approved between 2005 to 2015

Source: Coal Currency: Mapping Coal Project Finances in India.

http://www.cenfa.org/coal/coal-currency-mapping-coal-project-finances-in-india/

Note: Figures for lending are in rupees thousand crores.

At the national level, credit is mainly provided by public sector banks, the PFC and REC. As more and more power plants are unable to repay loans, most of the stressed and non-performing assets are seen in the books of NBFCs and PSBs.

As of July 2018, there were 34 thermal power projects with a capacity of 40 GW which were stressed. A total of Rs 1.76 lakh crore had been lent to them by various banks and financial institutions. Of these projects, around 10 stressed projects had been financed by State Bank of India.¹¹ Similarly, the PFC and REC disbursed loans of around Rs 47,700 crore to private power projects during the period 2013-14 to 2015-16; their NPAs in respect of such IPPs increased from 2.32% to 13.9% for REC and from 4.28% to 19.86% for PFC during the same period.¹²

The increase in stressed assets as a result of the power sector has brought lending to the power sector into renewed focus. Banks and other lending institutions have been criticised for their lack of transparency in making decisions to lend and failure to ensure that the power plants had a viable revenue source, which needed an assured fuel source and an agreement to sell power. Recently, the Comptroller and Auditor General of India (CAG) conducted a compliance audit of PFC and REC lending to private power projects, and found that the PFC and REC had not conducted appropriate due diligence while making loan decisions and had also deviated from their internal guidelines in this regard.

6.4 Classification of costs in the power sector

As seen in the previous section, a number of methods are available for evaluating the financial viability of power projects. In addition, as seen in the life-cycle cost method, different costs can be added depending on the overall objective of the analysis.

The basic structure of costs remains unaffected whether the projects is for generation, transmission or distribution. Broadly speaking, there are two main costs: the cost of equipment and construction of the project, and the cost of its operation. The cost of equipment and construction is called the ‘capital cost’. The cost of operation has many components and is clubbed differently for generation, transmission and distribution companies. Project owners approach the Electricity Regulatory Commissions with an estimation of operation costs. The total of the operation costs is what is required to be recovered through tariff by the project owner and is called the ‘Aggregate Revenue Requirement’ of the project. The operation cost includes the recovery of capital cost and the costs of running the asset. The capital cost is not recovered as a lump sum from consumers, but instead its cost is spread over the economic life of the project and recovered as a component of the operation cost. See Box 6.5 for more details regarding the concept of “life of a project”.

The commission is supposed to ensure the reasonableness and prudence of the costs incurred, for both the construction and operation of the plant, and ‘approve’ them. Only once approved can these costs be recovered from consumers as ‘tariff’. In what follows, we will take our examples from the previous section to discuss different types of costs.

6.4.1 Capital cost

This is the cost incurred by the company in the equipment and construction of the project. This includes the cost of the purchase of land, the engineering, procurement and construction of the plant, cost of overheads, and interest during construction. In our example in the previous section, Plant B’s capital cost was Rs 6500 crore. This capital cost consisted of many components, which are given in Table 6.14.

Table 6.14: Capital cost of Plant B

Particulars

Notation

Amount

(Rs Crore)

Land and site development

A

40

Plant and equipment

B

4500

Taxes and duties

C

360

Spares

D

150

Overheads

E

250

Hard cost

F = sum (A to E)

5300

Interest during construction (IDC)

G

1200

Total Capital Cost

H= F+G

6500

The funds for undertaking the expenditure of the capital cost (called ‘capital expenditure’) are raised from debt (loans) and equity (what the promoter puts in). Given the high magnitude of these costs, it is not possible to recover them in a short period of time. Therefore to smooth out the tariff impact, such costs are recovered over a long period, usually 25 years, depending on the term of the contract. The usefulness of the project and prudence check of the costs is evaluated at the time the investment is being approved. These are usually undertaken by the ERCs.

In addition to the original approved cost of the projects, during the course of construction or even after the plant has achieved commercial operation, there could be a need for additional capital expenditure. This would be typically on account of situations that could not have been foreseen by the developer. The regulator allows such ‘additional capital expenditure’ subject to a prudence check. It should be noted that any cost overruns arising out of factors that could have been controlled by the project developer cannot be considered as additional capital expenditure.

Box 6.5: Life of a project

As we discuss the kinds of costs and the different tools that are commonly used to compare these costs and benefits, it is important to understand the concept of the ‘life of a project’. It is important to distinguish between three kinds of ‘life’.

Economic life: This is the life that is considered when making the decision to build a plant. It is usually the average period for which long-term contracts are signed, and it is used since this is the maximum period within which the promoter is likely to recover costs. Normally, the economic life of conventional generation plants is 20-25 years.

Contract life: This is the time period for which a contract has been signed. This would depend on the kind of contract - short, medium or long-term. For a long-term contract, it is usually equal to or a little less than the economic life. The contract life or the ‘term’ of the contract directly affects the recovery of costs.

Useful life: This is the actual number of years a plant can operate for. With proper maintenance, conventional plants and transmission projects can operate for more than 25 years, and sometimes even 30-40 years.

In the days of integrated utilities, the generation, transmission and distribution assets belonged to the State Electricity Boards (SEBs). A generating station could continue to supply electricity till the end of its useful life. With the unbundling of SEBs and the introduction of competition in generation, a distribution company can today sign contracts of different durations, which has led to the introduction of concepts such as ‘economic life’ and ‘contract life’.

6.4.2 Costs of operation

The capital cost of the project, as discussed, is funded through a combination of equity and loan. Hence, loan repayment and profit on equity are legitimate costs that are to be recovered from the consumers through tariff. Under costs of operations we will first look at the charges used to recover the capital cost, which are ‘Interest on Loan’, ‘Depreciation’ and ‘Return on Equity’ (also known as the profit on equity). We will then look at the other costs, starting with the ‘Operation and Maintenance Expenses’. Box 6.6 provides more detailed information for some of these cost components.

Apart from the costs that are explicitly recognized and accounted for, most infrastructure projects also impose costs that are either not understood properly or are not accounted for at all. Such costs are often termed as hidden costs and externalities. Box 6.7 provides information regarding such costs.

Interest on Loan

The project owner has taken a loan to construct the project. She may need to take another loan in the future for other capital expenditure, say for replacing machinery. Interest on these loans needs to be paid by the project owner to the lenders (banks). She charges the interest payment to consumers as the ‘interest on loan’. The interest keeps on reducing as the principal amount of the loan is repaid and finally vanishes along with the loan. Interest payments are ‘passed through’, i.e. they are recovered through tariff from consumers. Thus, it is important that the project get a loan at a competitive rate so that its interest payments are low.

Depreciation / Repayment of Loan

Apart from the interest on loan, the principal amount of the loan also has to be repaid. The repayment of loan is not directly charged through tariff and instead a concept called ‘depreciation’ is used. Depreciation measures the reduction in the value of an asset due to ageing and use. Towards the end of the life of the asset, the value drops to a negligible amount. Depreciation is recovered throughout the life of the project (or a particular equipment), and the rate of depreciation is different for different equipment and assets. Depreciation is calculated as a percentage (%) of the cost of assets and is charged through tariff.¹³ It is usually charged until the asset is depreciated typically to 10% of its original value, after which no more depreciation is charged. The project owner is expected to repay the loan principal through this charge. Note that in our previous example, instead of separately accounting for depreciation, we had combined the repayment of loan and interest into one.

As the depreciation is recovered through tariff, the value of the equipment is reduced in the account books. This reduced value is referred to as the ‘book value’ of the asset or equipment (this is also known as the Net Fixed Assets). After some years, the asset becomes worthless in the account books, but has a lot of useful life left and has substantial market value. This happens, especially for the value of land or for hydro projects, which have a longer life than the term of contract.

Return on Equity

Most of the power sector in India runs on a ‘regulated rate of return’ model (see Chapter 7 for details). Under this system, the company operating the generation project, or a transmission or distribution system, is guaranteed a certain percentage of return on their equity, which is calculated on their gross fixed assets. This is referred to as the Return on Equity, and varies between 15% to 20% in India. This return is recovered through tariff and this charge remains applicable till the project remains in operation. Thus, if a generation plant is operational for 30 years, its project proponent will have received return on equity for 30 years.

Operation and Maintenance (O&M) costs

These cover the cost of repair of lines, meters, transformers or power stations. Only the routine operation and essential maintenance is charged to this head. Employee expenses, administration and general expenses, as well as repair and maintenance expenses are part of O&M costs. All these costs are recovered from consumers though tariff in the same year as the project owner pays for them. In our example with the three plants, the O&M expenditure consisted of employee expenses.

Box 6.6: Things to know

Interest During Construction (IDC) vs. Interest on Loan

Loans are taken to fund the construction of power projects. During the construction period, interest has to be paid on the loans. However, since the plant is not functional, this interest cannot be recovered through tariff. Thus, for the duration of the plant construction and till the plant becomes operational, the interest charged is called Interest During Construction (IDC). Once the plant becomes operational, this interest is added to the capital cost of the plant and hence, becomes part of the value of the plant (asset). For a project with no or minimum delays, the IDC is around 15% of the capital cost of the project.

The loan taken during construction may have a repayment period longer than the time taken for construction, so the interest on this loan would have to be paid once operations start as well. Some additional loans may also have to be taken in the future. The interest on these loans is paid off each year once the plant becomes operational as ‘interest on loan’.

Capital Expenditure and Capitalisation

Capital expenditure is the expenditure undertaken to create capital assets, i.e. to acquire a building, buy new equipment, etc. As mentioned, capital expenditure is spread over the life of the project for recovery and is not recovered lump-sum.

The process of spreading the costs of the capital expenditure over the life of the asset is done in two steps: (1) ‘capitalisation’ or the addition of (part or the whole) of the capital expenditure to the asset base of the company, and (2) depreciation. Now, as discussed, depreciation is already calculated on the existing asset base to pay for the original capital cost (or original asset base) of the company. Thus, the new capital expenditure through capitalisation adds to the original asset base of the company, and the depreciation is then calculated on this new amount. Thus, depreciation is used to pay back for the capital expenditure, original as well as additional.

Return on Equity and Depreciation

The capitalisation of expenditure adds to the asset base of the company. Much in the same way as the original capital cost, this capital expenditure is also financed via a combination of debt and equity. Once this capital expenditure is capitalised, the equity portion will be added to the Regulatory Equity, on which the Return on Equity (RoE) is calculated. Thus, capital expenditure adds to the basis for Return on Equity and hence, will lead to a higher RoE.

Income tax

Income tax of the utility on the base return (profit less incentive) is passed through to the consumer. Hence, the consumer pays for the utility profit as well as the tax on the profit. The tax computation is a complex process, especially in case of private companies which are subsidiary units of a larger group or company. Regulators often calculate tax either on normative basis or based on the claims made by companies and pass it on to consumers. Often, it is difficult for consumers to verify whether the company has indeed paid that much tax.

Non-Tariff Income and Other Incomes

This is the money received by an electricity company (generation, transmission, distribution) which is related to its electricity business, but is not through tariff. For example, items such as interest on staff loans and advances, sale of scrap, income from sale of tender documents or rebate on power purchase are accounted for as Non-Tariff Income by electricity companies. In addition, sometimes some other income unrelated to tariff may accrue to an electricity company. For example, Income from Other Business is an item considered by Maharashtra ERC, and Reliance’s distribution company in Mumbai earned Rs 2 lakh from kiosk advertisements which fell under Income from Other Business in 2014-15.

Both Non-Tariff Income and other incomes are subtracted from the amount to be recovered from the consumers, however, what is considered as other income and how it is to be managed depends on the ERC regulations.

Cost of Working Capital

The last and relatively small component of fixed costs is to recover the cost of obtaining working capital. The spares or the stored fuel (in the case of a generation project) are funded through working capital. The owner of the project can charge interest on the working capital in the tariff.

Costs and benefits are to some extent subjective concepts, and hence, the result of an analysis for the same project can differ based on who you ask and what you are measuring. Thus, how costs and benefits are defined is very important to the economics of a project.

Box 6.7: Hidden costs: Externalities

Costs and benefits are to some extent subjective concepts, and hence, the result of an analysis for the same project can differ based on who you ask and what you are measuring. Thus, how costs and benefits are defined is very important to the economics of a project.

Discussions around costs usually focus on conventional costs, i.e. those that appear on the account books. However, there are costs related to power projects that are paid for by the people or society at large but do not appear on the account books. These costs are called ‘negative externalities’ and are often not internalised by the sector, i.e. the project proponent does not adequately take into account the costs its power plants impose on the environment and on society.

As discussed in Chapter 1, electricity is a non-polluting form of energy at the point of use. But at the point of generation, especially for conventional plants, the social and environmental impacts of the power sector are very serious. Coal projects are responsible for carbon dioxide emission, which contribute to global warming. Coal burning creates ash as a by-product which is a source of heavy metal pollution. Fig 6.6 is a photo of a typical ash pond. Fuel combustion also results in the emission of different sulphur oxides (SOx) such as Sulphur Dioxide, different types of nitrogen oxides (NOx), particulate matter (PM) as well as carbon dioxide. SOx and NOx emissions cause acid rain which impacts crop yields. Hydro plants, dams and mines uproot thousands from their homes, and disrupt local cultures as well as the environment. The costs of these impacts, whether in terms of reduced fish catch, reduced forest cover or loss of livelihood, are paid for by the local residents and the society at large.

There have been attempts made to internalise some of these costs. The inclusion of R&R packages and the cost of installing Flue Gas De-sulphurisation (FGD) systems in the cost of the project, the imposition of conditions in the environment clearance, the levy of the environmental cess, etc are all attempts in this direction. However, it has remained difficult to ‘quantify’ these costs. World over, this is a contentious issue with not enough data or appropriate models for factoring in even the costs that can be computed.

Finally, there is the fundamental issue of whether these costs should be quantified at all. Some believe that the act of quantification itself leads to the commodification of nature and culture, and these should be protected for their own sake and not because it makes economic sense.

Figure 6.6: Ash pond and transportation of ash

Variable costs

Variable cost is a significant cost for fuel based power generation projects. Given that the fuel cost is the cost of the fuel used to generate electricity by the plant, it is dependent on the unit price of fuel (in Rs per unit of electricity generated) and the actual generation of the plant (i.e. the PLF of the plant). Hence, this cost is variable in nature, varying with the cost of fuel and the generation. The variable cost is recovered through the ‘energy charge’.

Here we have tried to capture broadly the idea of fixed and variable costs and the cost heads that fall under each of these costs. However, what costs fall under which heads is determined by the Electricity Regulatory Commissions (ERCs) through their regulations, and variations do exist. For example, while the CERC includes the cost of secondary fuel oil in fixed costs, the Maharashtra State ERC includes it in variable costs. Similarly, some ERCs have regulations wherein part of the O&M cost linked to the usage of the plant and equipment is also added to the variable cost.

Table 6.15: Revenue requirement for generation plant

Particulars

Notation

Amount

(Rs Crore)

Interest on Loan

A

370

Depreciation

B

470

Return on Equity

C

187

Operation and Maintenance Expenses

D

100

Interest on Working Capital

E

30

Income Tax

F

10

Less: Non-Tariff Income

G

20

Fixed Cost

H= sum (A to G)

1147

Variable Cost

I

1226

Aggregate Revenue

Required

J = H + I

2413

6.4.3 Clubbing the costs for recovery

The sum total of all these costs give the Aggregate Revenue Requirement, which is the amount of revenue that a regulated generation company will need to recover from its consumers through tariff. Let us assume that the costs of our generation plant are as give in Table 6.15.

As mentioned above, these cost heads are mostly the same across the companies, but are clubbed and recovered through different charges depending on the type of company. Generally, for generation companies, fuel costs are kept separate and recovered through the energy charge; all other costs form part of the fixed charge of generation plants. For transmission and distribution companies, the costs are clubbed together and then recovered through different charges.

In this chapter, we have seen the commonly used tools for the analysis of investment options in the power sector. We also looked at how costs are classified for projects in the power sector. The fixed and variable costs together give the total cost of a project and are recovered from consumers through tariff. In the next chapter, we will see how this tariff is determined in India.

Endnotes

¹ Here we are assuming that the distribution company has already decided to construct a new substation. Since this decision has already been made, now the design of the substation has to be decided upon. However, normally, the decision of whether to construct a new substation or not is an important one. In these cases, the tools will be used to evaluate between the two design options as well as the ‘do nothing’ option.

² Please note that the PV formula in Excel is for constant cash flow, while the NPV formula allows for varying cash flow. You can also calculate the NPV without the formula by calculating the PV of the cash flow for each year of the life of the substation, then summing it all up and subtracting the initial investment from it. Here we calculate NPV for Design A:

³ This has been calculated using the PMT function in Microsoft Excel.

⁴ Maharashtra Electricity Regulatory Commission (2017, December 14). Order in case no. 59 of 2017 in the petition of Maharashtra State Power Generation Co. Ltd. for approval of Capital Cost and Tariff of Koradi Generating Units 8, 9 & 10, Chandrapur Units 8 & 9 and Parli Unit 8. Retrieved from http://mercindia.org.in/pdf/Order%2058%2042/Order-59%20of%202017-14122017.pdf

⁵ Fairley, P. (2017, November 29). The complex web behind the siting of power plants. Nature, 551, S150-S152. doi: 10.1038/d41586-017-07511-2. Retrieved from https://www.nature.com/articles/d41586-017-07511-2

⁶ The PMT function gives a value for principal repayment + interest payment which will be the same every year and will completely eliminate the loan by the end of a specified period, which in our example is the period of loan.

⁷ We have taken the NPV of the total cost in Rs crore to get the life cycle cost.

⁸ Some find the idea of discounting a physical quantity like energy awkward. However, here the discounting of the energy generated is a result of formula jugglery and is not the discounting of actual energy produced.

⁹ The Debt Service Coverage Ratio (DSCR) is the ratio of the cash available to the debt service obligation of the project. It is a common measure used in finance since it indicates the ability of the project to generate enough cash to repay its debt payments (principal and interest).

¹⁰ Sengupta, A., & Athialy, J. (2010, September). Coal Currency: Mapping Coal Project Finances in India. Retrieved from http://www.cenfa.org/coal/coal-currency-mapping-coal-project-finances-in-india/. This report does not look into Foreign Direct Investment in the power sector.

¹¹ Parliamentary Standing Committee on Energy., (2018, August) 40th Report on Impact of RBI’s Revised Framework for Resolution of Stressed Assets on NPAs in the Electricity Sector. Retrieved from http://164.100.47.193/lsscommittee/Energy/16_Energy_40.pdf

¹² Comptroller and Auditor General of India., (2017)., Report No. 34 of 2017 on loans to Independent Power Producers by Rural Electrification Corporation Limited and Power Finance Corporation Limited. Retrieved from https://cag.gov.in/sites/default/files/audit_report_files/Report_No.34_of_2017_-_Compliance_audit_Union_Government_Loans_to_Independent_Power_Producers_by_Rural_Electrification_Corporation_Limited_and_Power_Finance_Corporation_Limited_Reports_of_.pdf

¹³ There are two common methods of calculating depreciation. As per the ‘straight line’ method usually adopted in the power sector, the allowed depreciation equals the division of capital cost by the life of the project. The amount of depreciation thus remains constant over the years. The ‘reducing balance’ method considers depreciation as a percentage of the ‘book value’ of the asset. As the book value declines, so does the depreciation.

7 : Electricity Tariff

Tariff is the rate at which electricity is sold to consumers. Every month we get a bill from our electricity company which mentions our consumption and the rate we have to pay for it. This bill is based on the consumer category-wise schedule of tariffs that we may have seen on our distribution company’s website or in its office. In this chapter, we will understand what exactly consumers are paying for - particularly, how the costs of generation, transmission and distribution are turned into tariffs and how consumer tariffs are determined.

We begin this chapter with a quick overview of some of the common methods of tariff determination. We then move on to understanding the method of tariff regulation in India as well as the process of tariff determination. Finally, we look at the trends in the tariff for the major consumer categories.

7.1 Methods of cost determination

Before moving further, it is important to understand that while the determination of the cost of electricity and its tariff often takes place through the same regulatory process, the two are distinct exercises. Costs are determined based on a certain regulatory method, such as say the cost-plus method that we explore shortly. However, tariff or more specifically consumer tariff - the rate at which electricity is sold to the consumer - is determined based on different considerations, such as the tariff philosophy (which determines the extent of cross-subsidy) and subsidy provisions. Thus, once the costs to be recovered are determined, tariff determination is a process of deciding how to recover these costs and from whom.

There are different methods available for assessing the revenue requirement or total costs of an electricity company. In India, the most commonly used method is based on ‘cost-plus’ pricing. We will review this and other methods in this section, as well as their advantages and limitations.

7.1.1 Cost-plus method

Under ‘cost-plus’ regulation, the tariff is set such that the company (generation, transmission or distribution company) is allowed to recover all its prudent costs plus is provided with a reasonable rate of return. Prudent cost implies that the expenditure was undertaken after evaluating all possible alternatives and choosing the least cost one out of them. In this method, the regulator scrutinises all the costs and decides whether they are prudent or not. Unreasonable costs are disallowed and do not form a part of the revenue to be recovered through a consumer tariff, whereas prudent costs are approved. Approved costs plus the rate of return make up the total revenue requirement of the company, which is recovered through tariff.

The ‘cost-plus’ method, also known as the ‘rate of return’ regulation or ‘cost of service’ regulation, is commonly used to regulate the consumer prices in monopoly industries. Most electricity companies were originally integrated utilities, i.e. they were a single company with generation, transmission and distribution functions. They were also monopolies in their supply areas and faced no competition from rivals, but in return they would have to give up their right to set tariff, which would be set by regulators. ‘Cost-plus’ regulation provided for a kind of compromise between the companies and the regulator¹ (in India, the state government was the regulator till the commissions were established). The company would also be obligated to supply electricity to anyone and everyone in its supply area who demanded electricity and it would do so at the regulated price. However, to keep companies interested in reliably supplying electricity to all consumers in such a system, a fixed rate of profit is also guaranteed.

The cost-plus framework has advantages as well as limitations. The regulator examines whether the expenditure was necessary and procured at least cost, and can disallow wasteful expenditure. This threat of disallowance of unnecessary or inappropriate expenditure is supposed to provide incentive to the company to be efficient.² However, while prudence check avoids most obvious adverse outcomes, it is often difficult for the regulators to identify all inefficient expenditures, especially since the regulated company has an informational advantage over them. Since the regulator can monitor the performance of a utility only imperfectly and that too after the costs have been incurred, the threat of disallowance lacks credibility in many cases. The process is also time-consuming since it involves an in-depth review of each cost head. Finally, cost-plus regulation tends to promote overinvestment in capital assets, since the rate of return (and hence, profitability) is tied to capital investments. This is referred to as ‘gold-plating’ of investments.³

7.1.2 Performance based regulation

Performance based regulation is an extension of the cost-plus approach. Under the performance based approach, the regulator sets targets for key performance and cost parameters and calculates the total revenue requirement assuming that these targets are met. If the utility performs better than the target, it makes some more profit (over and above its regulated rate of return), and if it falls short, profits are reduced. Hence, this method offers the companies an incentive to improve efficiency and reduce costs. The targets are called ‘normative parameters’ and are usually set for performance indicators such as distribution losses, availability of the transmission system, and station heat rate and plant load factors for electricity generation. However, for this approach to be effective, the regulator should have an in-depth understanding of both the costs as well as potential gains from efficiency improvements. Profit sharing is often used with this method in order to prevent the company from making windfall profits. If the utility makes a profit, it cannot keep all of it and has to share a part with the consumers.

Utilities find such a cost determination approach more predictable, especially in the medium term (3-5 years). If properly administered, such methods encourage utilities to reduce costs and improve efficiency while providing consumers with tariff certainty for a few years. The achieved cost reductions then get captured in the next tariff-setting period, and hence, also protect consumer interests. But making correct guesses about the likely costs and feasible efficiency improvements requires a mature regulatory process, solid data regarding performance of the company, and sufficient understanding of a utility’s business. In addition, it is important to have chosen the right efficiency parameter and to monitor the achievement of targets.

Box 7.1: Performance based regulation: The experience in the UK

The United Kingdom (UK) adopted the price-cap regulation (called ‘RPI-X’) in 1984 to regulate the profits of the then recently privatised British Telecom (BT). Since then, this model of regulation has been adopted across different infrastructure sectors, including the energy sector, in the UK. Under this system, the regulator undertakes a detailed performance review and sets the tariff trajectory for a specified time period (the ‘control period’). It is important to mention that wires and supply are separated in the UK with only the wires business being regulated, while supply prices are market determined. The tariff trajectory is such that the tariff is allowed to increase each year at the rate (RPI-X) per year. Here RPI is the Retail Price Inflation and X is the rate by which the regulator believes the companies should be able to increase efficiency year on year. To make this work, the commission requires an in-depth understanding of the likely costs, expected sales growth, as well as the achievable efficiency gains and hence, the price-cap regulation saw an increase in data requirements and analysis in the UK.

The two most common forms of RPI-X regimes are the revenue cap and the price cap, which are discussed briefly here:

Revenue cap

In this method, the allowed revenues of the utility are capped and the utility is allowed to set tariffs to recover the costs. This method removes the incentive for the utility to increase its sales per customer. This approach is therefore considered to be conducive to the promotion of energy efficiency and demand-side management programmes. This method is not very commonly used.

Price cap

This method assigns a ceiling under which the price may fluctuate. Unlike the revenue cap method, it provides incentives for the distribution company to expand its electricity sales, assuming that the rates are higher than the marginal cost. Price cap regulation offers incentives to utilities to promote sales, especially during off-peak hours.

After a two-year long review process of these regulations (called ‘RPI-X@20’), the UK regulator Ofgem decided to introduce a new regulation for electricity and gas prices called the RIIO (Revenue = Incentives + Innovation + Outputs). This model was built on the existing RPI-X regulation and added incentives for better service delivery and network improvement as well as provided funds to promote innovation in the transmission and distribution wires business. It also increased the control period from five to eight years. The current RIIO for electricity distribution (called ‘RIIO-ED1’) is from 2015 to 2023.

7.1.3 Market determined tariff

Competition in electricity is generally taken to mean competition in the generation and sale of electricity (wholesale and retail). Transmission systems, distribution wires and system operation are seen as natural monopolies, and non-discriminatory access to these is considered essential for competition. In case of retail supply, it is argued that the principles of demand and supply of the market can set correct and more efficient tariffs. In such a market based system, the role of the regulator changes to ensuring competition and preventing misuse of market power by dominant players. Thus, moving towards market-based tariffs involves increasing competition in the sector (i.e. increasing the number of buyers and sellers), and having tariffs that reflect the marginal cost of producing electricity at a given point in time.

In India, competition and market based tariffs have been introduced in the generation segment since 2006. This was done under the E Act, which also mandated unbundling the vertically integrated electricity boards and delicensed generation, thus allowing investors to set up power plants. Under these provisions, generation tariff is determined by an auction-based mechanism, with the generation companies competing to supply electricity to the distribution companies. In addition, large consumers of electricity are also allowed to purchase electricity directly from generators and traders of electricity in this wholesale market.

7.2 Method of tariff determination in India

Before we look at the tariff fixation process through an example, in this section, we provide a brief explanation of the regulatory principles and process of costs approval and tariff fixation in India.

In India, a mix of cost-plus and performance based regulation is used. The state ERCs set normative performance parameters that electricity companies have to meet and based on the actual performance, all prudent costs and a regulated rate of return, is allowed to be recovered through tariff. If any of the normative parameters are not met, then some costs are disallowed.

7.2.1 A hybrid method

Before the ERCs were established, the State Electricity Boards (SEBs) were authorised to set consumer tariffs so as to achieve a surplus of 3% on the value of fixed assets. In practice, however, the state governments approved the tariff.

The E Act retained the ‘cost-plus’ approach but introduced important changes. The state commissions now undertake the tariff determination process and set consumer tariffs. The process of cost approval and tariff determination is based on regulations issued by these commissions. The E Act has also mandated the move towards performance based regulation as well as multi-year tariff regulations (we discuss this later in the chapter). Thus, the method of tariff determination used in India is a hybrid of cost-plus and performance based regulations.

All costs of generation, transmission and distribution companies, along with any other system costs, are recovered through the tariff paid by the distribution company’s consumers. These costs plus regulated return that is allowed to these companies, is the total revenue that is recovered through consumer tariff. Figure 7.1 shows a simple schematic of electricity and money flows in a state level power system. Consumers pay for the costs of the entire value chain of electricity to the distribution company, which in turn pays to the generation and transmission companies. Power purchase costs tend to be the largest component of the distribution company’s costs and hence of the tariff paid by the consumers. Table 7.1 provides a percentage split of the costs incurred by the distribution company in Maharashtra.

Figure 7.1: Electricity and money flows in a state level electricity system

Source: Prayas (Energy Group)

Table 7.1: Percentage split of costs of Maharashtra DISCOM FY 2017-18

Component

Percentage of Tariff

Power purchase (incl. inter-state transmission charges)

73%

Intra-state transmission charges and SLDC fee

7%

Distribution cost

20%

Source: MERC tariff order in case no 195 of 2017

7.2.2 Typical tariff process in India

The ERCs determine the cost-plus tariffs for the entire system (i.e. generation, transmission and distribution), although its determination of consumer tariffs (i.e. tariffs of distribution companies) is its most well-known regulatory process. The tariff determination process usually begins with a tariff proposal and concludes with a tariff order. It usually takes 3-4 months and starts in November for deciding tariffs that would be applicable from April of the following year. Figure 7.2 provides a schematic of the tariff determination process for a distribution company. Please note that not all state commissions follow the same schedule or steps in the tariff determination process.

Figure 7.2: Tariff determination process for a DISCOM

Source: Prayas (Energy Group)

Note: The above schematic is based on practice prevalent in Maharashtra. As per the E Act, the regulatory commissions are required to issue tariff orders within 120 days of receipt of a duly filed tariff petition.

Let us look at the tariff process for a distribution company in more detail. The company approaches the ERC for the first time with its estimates of its costs for the next year. The ERC will look at the estimates, ensure that these are based on prudent expenditures, and then ‘approve’ the costs and determine the tariff. This ‘approved’ tariff is what is to be charged to consumers for the tariff period and will form the revenue of the distribution company (See Figure 7.3).

Figure 7.3: Indicative timeline for Tariff process for a financial year ‘t’

Source: Prayas (Energy Group)

Note: The schematic is based assumption of timely submission of petitions and audited actuals by the DISCOM. In case of delays in filing of the petition or the required data, the true-up order may get delayed beyond the indicated time frame of t+1.

However, the tariff that is ultimately charged may be different due to the imposition of fuel surcharges and the provision of subsidies. For example, the generation cost may become more or less expensive if the price of coal suddenly changes, which will result in the power purchase cost of the distribution company changing. If the tariff order comes out at a later date, the company may only be able to charge the new tariff for the following months. At the end of the tariff period, the companies come to the ERC and present their ‘actual’ costs and revenues, i.e. the costs that were actually incurred and the tariff that was actually charged. This is the ‘true-up’ process and is a reconciliation of the approved costs and revenue with the actual costs and revenue. The ERC usually asks for explanations and justifications for any divergences between the approved costs and revenue at the beginning of the period and the actual costs and revenues. Divergences not found to be prudent or justifiable are disallowed. After the final approval, any mismatch left between the distribution company’s costs and revenues (referred to as the ‘revenue gap’) will then be added to the costs to be recovered in the following year.

7.2.3 Multi-year tariff process

The annual tariff filing process is often too time consuming for both the regulators and the companies. It also lowers the incentive for the company to cut costs since the regulator would generally pass on the benefit of efficiency improvement to the consumers immediately in the following year. To address these problems, the idea of multi-year tariff (MYT) has been promoted in the E Act, as well as the National Tariff Policy. Most of the state ERCs in India have moved to setting MYT tariff instead of setting tariff annually.

Under the MYT process the control periods are usually between 3 to 5 years, and the costs and revenues for each year within the control period are projected. Normative performance parameters called ‘controllable’ factors may be defined by the commissions, such as the normative level of distribution losses, collection efficiency, station heat rates, transmission availability, etc. Financial incentives are provided for meeting the norms, while the utility may be penalised for not meeting the same. For example, in Maharashtra, the power purchase cost is an uncontrollable parameter, while the O&M expenses are controllable. Thus, power purchase costs are subject to the usual prudency and efficiency checks, while O&M expenses can increase only by a certain percentage each year. We shall see more of how these norms are used in the section on tariff determination.

7.2.4 Role of competitive bidding for power procurement

For procurement of power under the E Act, a distribution company has two options: it can either enter into a regulated contract to purchase power with a generation company (under Section 62 of the Act), or it can undertake competitive bidding to discover a generator willing to supply electricity at the lowest rate (under Section 63 of the Act). In the former option, the contract needs to be approved by the commission after due scrutiny (since the generation tariff is cost-plus); in the latter option, the regulatory commission has to approve the resultant agreement between the distribution company and the lowest bidder if the bidding process is found to be valid.

How does competitive bidding work?

The 2005 bidding guidelines provide a two-part generation tariff structure comprising of fixed (also called capacity) and variable (also called fuel or energy) charge. Variable charge has sub-components of fuel cost, transportation and fuel handling with the option of quoting escalable and non-escalable charges for each of these sub-components. Escalable parameters allow bidders to transparently pass on potential price variations for each of the sub-components. By allowing the bidder to quote escalable and non-escalable parameters, the guidelines provide complete flexibility to bidders in terms of handling of the various risks associated with the fuel price variation, etc. The bids are evaluated based on the levelised tariff⁴ and power purchase agreement (PPA) is signed with the lowest (L1) bidder.

Once the power purchase agreement is signed, the discovered tariff can be modified only under limited circumstances such as changes in law and/or force majeure events. The extent to which the tariff can be revised under these circumstances is also defined in the contract. Thus, the bidding system provides a level of certainty regarding tariff to the distribution company and hence to the consumers. However, in the recent past, quite a few projects that have won contracts through bidding have also sought revision of discovered tariffs. These claims have been contested by distribution companies and consumer representatives, and many of these matters are pending before various forums (read more about this in Chapter 9).

In case of regulated generation projects, the commission needs to evaluate the prudence of each and every cost claimed by the generation company as well as stipulate performance standards for them. The regulatory experience so far suggests that such generation projects are typically unable to limit the costs to the level specified by the regulator or estimated by the generator at the time of seeking approval for the project. Generation companies often claim an inability to comply with performance norms owing to time overruns, changes in fuel quality, availability and price, and other issues.

7.3 Tariff process for distribution, transmission and generation

In this section, we begin with a simple stylised example of how the tariff process works and how charges for consumers come to be determined. The first step of this exercise is the assessment of the revenue requirement of the company. Once all the prudent costs have been assessed and approved, the regulator then decides how the revenue required to meet these costs can be recovered through tariff that is to be charged to various consumer categories. In our example, we will look at the tariff determination process of a distribution utility, generation company and transmission company. The process described below can be applicable to an annual as well as multi-year tariff process.

As before, we start from the consumer end and hence, with the distribution tariff. However, since the tariff process often happens in parallel for generation, transmission and distribution companies, you can also read about the tariff setting process for any of the components. Let us start!

7.3.1 Distribution tariff

The distribution company is responsible for procuring the least cost electricity for its consumers and supplying it to them in a reliable manner, ensuring a decent quality of supply. For this to happen, the distribution company has to carefully assess its demand and plan for power procurement. The following stages are followed by the distribution company to arrive at the tariff: (1) demand estimation, (2) power procurement planning, (3) estimating distribution costs, (4) determining the annual revenue requirement and (5) fixing consumer tariffs and determining revenue gaps, if any.

1. Demand estimation

The power requirement for the next year (or the next few years in case of multiple years as in the case of multi-year tariff proceedings) is estimated by the distribution company based on past consumption and growth data as well as any expected increase or decrease in demand in its area. This is done by estimating the sales to different categories of consumers and the T&D losses. Most companies prepare these estimates both in terms of energy demand (MU) as well as power demand (MW). We will look at this planning process in more detail in Chapter 8. The demand estimation is further divided into (a) estimation of metered sales, (b) estimation of unmetered sales and T&D losses, and (c) estimating the daily and annual load curves.

a) Estimation of metered sales

Estimation of metered sales is usually an extrapolation of the existing figure based on a rate arrived at by making certain assumptions for expected growth rate and past trend of consumption. The growth rate is in turn based on changes anticipated in the number of consumers and assumptions pertaining to broader economic growth rate. Detailed surveys may also be undertaken to determine consumption by certain types of consumers. In addition, other factors influencing the demand estimation must also be taken into account. For example, one such factor is the possibility of consumers moving to open access or captive generation based on the past trend for such migration and other factors that may encourage or discourage it.

b) Estimation of unmetered sales and T&D losses

Estimation of unmetered sales is based on expected growth in the number of such consumers and past trend of consumption. Depending on the kind of sales, for example say agricultural sales, factors such as changes in connected load or pattern of supply and usage, also play a role in the estimation. The total energy fed into the grid is metered at the generation stations and the export/import substations (where power is exchanged with neighbouring utilities). The difference between the power fed into the grid and the total energy sold is the T&D loss. As seen before, energy sales consist of metered sales (which are measured) and unmetered sales (which are estimated). Hence, estimates of unmetered sales have a direct linkage to the T&D loss (see Box 7.2 for more details). If the estimate of unmetered sale is high, the T&D loss would appear to be low and vice-versa, as we explain further in this section (read more about T&D loss in Chapter 4).

Several commissions have started asking utilities to meter a sample of agricultural (or other unmetered) consumers. The representative nature of sampling is a contentious issue in several states (See Section 7.4 below).

We have seen in Chapter 4 that as electricity journeys from the generating station to the consumer’s location, losses occur in the transmission system as well as distribution system. In the distribution system, the losses can be technical losses (system losses) or commercial losses (electricity theft or non-payment for electricity). A distribution company has to take into account the losses it will incur and buy enough power. Thus, if the distribution utility is buying enough electricity to cater to all of its demand, then it has to buy not just the amount it will sell to final consumers but also the electricity it will lose in getting the electricity to the final consumers (i.e. T&D losses). The total energy supply requirement is the sum of the estimate of metered sales, unmetered sales and the T&D loss.

Box 7.2: Unmetered sales and T&D losses

In this box, we will look at a stylised example for the determination of distribution tariff in a step-by-step manner. We will assume that the entire system works on the cost-plus method. As mentioned in the previous section, in the cost-plus system, the company is allowed to recover all prudent expenditure plus a guaranteed rate of return determined by the appropriate electricity regulatory commission.

Our distribution company has Power Purchase Agreements (PPAs) with various generation companies. The PPAs give the quantum of power that the distribution company will buy from the generation company, as well as the other responsibilities of the parties. In our example the PPAs are regulated (cost-plus) PPAs, and hence, the rates of the sale of power are determined by the regulator. The distribution company also has a Bulk Power Transmission Agreement with the transmission company which includes the terms and conditions under which the distribution company can access the transmission system, i.e. use the transmission system to have its electricity moved from the generating station to itself.

(a) Estimation of metered sales: Let us assume that the estimated metered sales are 4600 MUs in
2018-19, split into the categories seen in Table 7.2:

Table 7.2: Estimation of metered sales

Distribution companies have many categories for their consumers, and different distribution companies may have different categories. Here we assume only the above categories of metered consumers.

(b) Estimation of unmetered sales and T&D losses: Let us assume that the estimated total unmetered sale of our hypothetical distribution company is 900 MUs and the loss estimations are as in Table 7.3.

Table 7.3: Estimation of unmetered sales and T&D losses

Source (Table 7.2 & 7.3): Prayas (Energy Group)

In our example, the distribution company needs to purchase 7190 MUs at the generation-transmission periphery to be able to supply 5500 MUs to its consumers (metered and unmetered) given the loss levels. In what follows, we look at the decisions for 2018-19; decisions for the following years would be made in the very same manner.

As mentioned, increasing unmetered consumption can make the transmission and distribution losses of a utility look small. This relationship is captured in the diagram below:

The practice of inflating unmetered sales to under-report T&D losses is quite prevalent and since the advent of the ERCs, agricultural consumption has been restated several times in various states. We will discuss this issue in more detail under Section 7.4.2.

Let us see how this works using our example. In our example, we know that the unmetered consumption is estimated at 900 MUs. This gives us a total estimated sales figure of 5500 MUs. Now, in order to sell this quantum of electricity, the distribution company will need to procure 7190 MUs. Thus, 1690 MUs
(7190-5500) are lost due to transmission and distribution losses. However, since the unmetered consumption is only estimated, if the distribution company inflates the sales to this category to 1200 MUs, this would increase the total sales figure to 5800 MUs. So now, it seems that the distribution company is selling 5800 MUs while purchasing the same amount of input energy, i.e. 7190 MUs. Thus, its losses would appear to be 1390 MUs which is lower by 300 MUs (1690-1390).

2. Power purchase plan

After estimating the energy supply requirement, the next decision to be made is to find the least cost mix of generation stations to provide this electricity. This also involves making decisions regarding purchase from sources other than capacity contracted under medium or long term PPAs, such as purchase from the short term market in case the costs of electricity available there are lower. While the distribution company would typically have some existing medium or long term PPAs, it can also plan to sign more such PPAs if its demand is expected to grow significantly in the future (see Box 7.3 for more details). In case of any gap between supply and demand, the company will need to either buy the required power from market, which can be costly, or undertake load shedding by cutting off supply to certain areas.

3. Estimating costs

Power purchase cost, which includes costs for renewable energy procurement, short term power purchase and purchase from long/medium term PPAs, is usually the largest component of the costs of a distribution company, accounting for around 60-70% of the total costs. In addition to the power procurement cost, the distribution company also pays the transmission charges - the intra-state transmission charges (for use of the intra-state transmission lines), and the inter-state transmission charges (for use of the inter-state transmission infrastructure for receiving power from generation stations located not in its state) - as well as the State Load Dispatch Centre (State LDC) charges.

The distribution company also has to incur other expenditure in order to run its distribution business. These expenditure heads should be familiar to you from Chapter 6. In brief, the distribution company has operation and maintenance (O&M) expenses, depreciation charges (principal repayment), interest on loan, return on equity, interest on working capital, and income tax to pay. In addition, the distribution company also has some distribution specific costs, namely the interest on consumer security deposits (which it pays on the security deposits it takes from its consumers), the provision for bad and doubtful debts, and the contribution to contingency funds. Finally, the non-tariff income and income from other businesses is subtracted from the total costs of the distribution company.

Box 7.3: Power procurement planning

Continuing our stylised example, let us assume that there is no load shedding. Let us also assume that the power purchase options available to our distribution company are as listed in Table 7.4.

Table 7.4: An example of power procurement planning

*Power in the short-term market is sold as a single tariff

The generation tariffs of these PPA projects would have been decided separately by the ERCs (See Section 7.3.4 Generation Tariff). Given these options, there are different combinations and hence, different choices available to the distribution company to fulfil its purchase requirement of 7190 MUs in 2018-19 and they all come at different prices. Let us have a look:

It is clear that the distribution company should purchase power from Power Plant 1 since it is the cheapest and it already has a PPA with the distribution utility.

The distribution company could buy power only from its PPA power plants, scheduling the full 7190 MUs from Power Plant 1 and the remaining from Power Plant 2 (by running it at a lower PLF). It would have to pay Rs 612 crore to Power Plant 1 (for 3723 MUs) and Rs 1040 crore to Power Plant 2 (for 7190 - 3723 = 3467 MUs). In addition, it would have to pay the fixed cost for both, i.e. Rs 300 crore. The total cost for this option then is Rs 1952 crore.

Alternatively, the distribution company could buy 3723 MUs from Power Plant 1 and the rest from the short term market. In this case, it would pay the same Rs 612 crore to Power Plant 1, but pay a lower rate for short term power at Rs 867 crore (for the remaining 3467 MUs). However, in this case as well the distribution company will have to pay the fixed cost of the PPA power plants, since under the clauses of the PPA the fixed cost has to be paid for a power plant even if its generation is not purchased. Hence, the distribution company will have to pay Rs 300 crore as fixed cost. The total cost for this option is Rs 1779 crore.

Let us assume that the utility chooses the latter option. Thus, Rs 1779 crore is the cost of power procurement for the distribution company.

It is important to note here that in the Indian context, short term markets are volatile and subject to price fluctuations, and hence are supposed to be only a small percent (typically upto 5%) of the overall power purchase of the DISCOM. The above example is merely used to demonstrate the need for evaluating all possible options to ensure least cost procurement.

4. Annual revenue requirement

The power purchase cost, the transmission and LDC charges, the distribution company costs and taxes all form part of the Annual Revenue Requirement (ARR) of the distribution company.

ARR = reasonable costs + allowed profit

5. Fixing consumer tariffs (retail supply tariffs) and normative parameters

The distribution company files a petition with the state ERC for approval of its ARR as well as determination of its tariff. When the state ERC takes a decision on the ARR of the utility, it looks at the estimates made and costs determined by the distribution company to ensure that they are prudent. It then ‘approves’ the ARR, which is to say that it allows the distribution company to recover that approved amount of money from consumers. The state ERC also decides how the approved costs are to be allocated amongst various consumer categories through tariff. Whatever is not recovered through tariff or sales migration charges forms part of the losses or revenue gap, which is carried forward for recovery in coming years along with the carrying cost.

Dividing the annual revenue requirement (in Rs Crore) by the sales (in MUs) gives the average cost of supply (ACoS), an important metric which assesses the costs the distribution company incurs to supply one unit of electricity to consumers.

ACoS is the amount that would be paid by all consumers if they were all charged the same tariff. However, we know that all consumers are not charged the same tariff. Therefore, the major questions that the state ERC has to deal with relate to: (a) allocation of ARR between different consumer categories, and (b) allocation of ARR between different charges to be levied (for example, fixed charges and energy charges). The tariff decisions of the commission are based on the sales mix of the distribution companies (how much is say, residential, industrial and agricultural consumption), the amount of cross-subsidy and the consumers’ capacity to pay as well as other social considerations. The tariffs decided and approved by the commission are shown in the tariff schedule of the distribution company. Figure 7.4 captures the major steps of the process discussed so far.

Figure 7.4: Major steps in tariff determination

Source: Prayas (Energy Group)

In India, small domestic consumers, farmers, agriculture-based enterprises, and a few other types of consumers pay a tariff lower than the ACoS, whereas large industries pay a tariff higher than the ACoS. Thus, the tariffs are designed in a manner that the loss to the distribution company from supplying to consumers with a low tariff is made up by the higher tariff charged to industrial and commercial consumers. Such a subsidy between the consumer categories is referred to as ‘cross’ subsidy.

Since the bill paid by the consumer may include fixed and energy charges, as well as other charges, the effective tariff is different from the slab-wise charges typically given in a tariff schedule. The Average Billing Rate (ABR) is a useful concept when thinking about tariff that is effectively paid by the consumers. To calculate the ABR, the total revenue from a category of consumers is divided by the total sales for that same category. See Box 7.4 for illustrative calculation of the ABR and ARR.

Box 7.4: Annual Revenue Requirement and tariff determination

The Annual Revenue Requirement (ARR) is the sum of all the costs claimed by it against each of the cost heads. In case of our distribution company, an illustrative ARR is presented in Table 7.5.

Table 7.5: Illustrative Annual Revenue Requirement (ARR) of a distribution company

Particulars

Amount (in Rs Crore)

Power purchase cost

1779

Transmission charges

200

Load Dispatch Centre (LDC) charges

11

Operations & Maintenance (O&M)

400

Depreciation

70

Interest on long term loans

60

Interest on working capital

40

Return on equity

170

Income tax

80

Less: Non-tariff income

20

Annual Revenue Requirement (ARR)

2790

Source: Prayas (Energy Group)

Load Dispatch Centres and their Annual Revenue Requirement

The Load Dispatch Centres also employ persons and invest in equipment and software. They too incur operating expenses and capital expenditures, and receive a return on equity. They recover their ARR from the LDC charges levied on those using the transmission system called Transmission System Users, and are divided amongst these users based on their peak demand (much in the same way as the transmission tariff, see Section 7.3.3 below). In our example, we assume that our distribution company’s share of the LDC charges is Rs 11 crore.

Continuing the illustrative calculation, let us say that the average cost of supply (ACoS) of our distribution company is Rs 5.07 per unit. Assuming certain values for sales, and fixed and variable charges for the various consumer categories, we can compute the revenue that can be recovered. This calculation is shown in Table 7.6. As can be seen, the company can recover Rs 2441 crore.

Table 7.6: Illustrative calculation of category-wise revenue that can be recovered at a given tariff

Source: Prayas (Energy Group)

Now that we have consumer category wise revenue and sales, we can calculate the average billing rate (ABR) for each category. Table 7.7 illustrates this calculation for the different categories of consumers.

Table 7.7: Illustrative calculation of consumer category wise Average Billing Rate (ABR)

Source: Prayas (Energy Group)

Thus, the ABR gives a single comparable figure across different consumer categories. Using the ABR and the ACoS, we can also see the level of cross-subsidy included in the tariff as determined by the ERC. This can be seen in Figure 7.5.

Figure 7.5: Level of cross subsidy included in the tariff for different consumer categories

Source: Prayas (Energy Group)

There is no fixed rule for what percentage of the ARR will be recovered as fixed charges. In our example, we assume that Rs 349 crore will be recovered as fixed charges and the rest as electricity charges. Fixed charges are calculated in Rs per KVA per month (i.e. based on connected load, especially for HT consumers) or in Rs per month (usually for LT consumers). In our example, we calculate it in Rs per month for all consumers. Thus, in our example, the consumers will pay the fixed cost rate irrespective of their consumption.

In our example, Rs 2441 crore have to be recovered through energy charges. The energy charge is usually calculated in Rs per unit, i.e. it varies with consumption.

The charges are as follows:

Fixed charges: As we saw in the case of generation companies in Chapter 6, distribution companies too have a certain fixed expenditure which it incurs on the creation and maintenance of basic infrastructure facilities for supplying electricity to consumers. These costs are recovered through ‘fixed charges’ (not to be confused with the ‘fixed cost’ of the generation companies), also called ‘demand charges’, from the consumers. Each month, the consumer has to pay this specific fixed amount even in the absence of electricity consumption. This charge is mainly towards electric cable network, transformers, substations, etc. and is supposed to be determined based upon the total connected load of the consumer and the type of connection (single-phase or three-phase).

However in India, the demand charge is usually less than the amount required to fully recover the fixed cost of the distribution company. Presently, most DISCOMs recover about 14% of the total revenue from fixed charges while almost half of their expenses are due to fixed costs.

The fixed cost to a utility for supplying power varies from house to house, depending primarily on its location. The cost of a new connection to a house in a remote village can be very high. But it is obvious that the full cost is not recovered from such consumers. It is averaged over all other consumers. In some cases, the fixed charge also increases with the consumption level or connected load. In some states, the fixed charge is higher for three-phase supply compared to that for single-phase supply (three-phase supply typically indicates higher consumption levels). The monthly fixed charges can be linked to the voltage level, connected load (of the consumer’s premises), or maximum power demand of the consumer in a month, or a combination of these values.

Energy charges: The cost that the company incurs on power purchase is supposed to be recovered through the energy charge, which is the cost per unit of power consumed. As mentioned above, the energy charge is different for different categories of consumers.

In addition, for some categories, it is a telescopic tariff wherein the rate for the initial units is low and gradually increases for subsequent units. This is to subsidise low consumption, especially in the residential segment. Here, the tariff increases with increasing consumption (for example, the first 50 units are charged at a lower rate, the next 50 at a higher rate, and so on). As a result, higher consumption leads to a higher tariff.

Thus, the charges are split into consumer categories (such as domestic, non-domestic, industrial) and further into consumption slabs (0-50, 51-100, and so on). In addition, the Electricity Regulatory Commission has created another sub-category of domestic consumers called BPL / Kutir Jyoti (Below Poverty line) consumers.

Other charges: Other than those mentioned above, any other charges approved by the state ERC are recovered from the consumers as ‘other charges’. These are usually specified in the schedule of charges and are revised periodically, say once in five years.

Electricity duty: In addition to the tariff set by the state ERC, state governments usually levy a tax on the sale of electricity called the ‘electricity duty’. This tax is indicated separately in electricity bills and collected by the utility on behalf of the state government. The revenue from this tax is accounted for in the state government’s budget receipts. Neither the state ERC nor the distribution company has any control over this tax. The tariff being discussed in this section excludes this tax.

Cross-subsidy and government subsidy

Social considerations have always played a key role in shaping tariffs especially since electricity is considered an essential service. Households and other small consumers using very little electricity indicate a poor population. In India and in many other countries, these consumers are subsidised and pay a low charge for initial consumption (this initial consumption is calculated as the bare minimum consumption or ‘lifeline consumption’), and the subsidised tariff for this consumption is referred to as the ‘lifeline tariff’. Similarly, agricultural consumers and powerlooms also have typically been subsidised to encourage agriculture and employment in powerlooms. Thus, these categories of consumers pay a tariff lower than the Average Cost of Supply (ACoS). The loss to the distribution company as a result of this lower tariff is made up by charging certain other consumers a tariff higher than the ACoS. As seen in our stylised example, the distribution tariff for our unmetered consumption, LT (0-50 units) and BPL households was below our ACoS of Rs 5.07, while that of all other consumers was above ACoS. This subsidy which facilitates lower prices for some consumer classes, or for some users within the same consumer class, is called ‘cross-subsidy’. As we have seen earlier, the cross-subsidy has not only subsidised poor and agricultural consumers, but also covered some of the inefficiencies of the distribution companies (see Section 7.3.1 again).

The cross-subsidy needs to be distinguished from the government subsidy. Let us understand government subsidy through our stylised example. In our example, the regulatory commission had set the unmetered consumption (agriculture) tariff at a flat rate of Rs 100 per month. Now let us assume that the state government of our hypothetical state where our distribution company operates decides to subsidise agriculture. It decides that it wants agricultural consumers to pay no more than Rs 30 per month to the distribution company as tariff and it would subsidise the difference. This can be seen in Table 7.8.

Table 7.8: Government subsidy to agricultural consumers

Particulars

Units

Amount

Unmetered consumers

numbers

200000

Unmetered consumption (agriculture) flat rate as

determined by ERC

Rs per month

130

Revenue to DISCOM from unmetered consumers

Rs crore

31

Unmetered consumption (agriculture) flat rate as

determined by state government

Rs per month

30

Difference (or government

subsidy)

Rs per month

100

Government subsidy to DISCOM

Rs crore

24

Source: Prayas (Energy Group)

As can be seen from the table, the revenue that the distribution company was getting from agriculture consumers is Rs 31 crore. In order to bring the tariff paid by farmers to the distribution company down to Rs 30 per month, the government will pay the difference to the distribution company. This comes to Rs 24 crore (i.e. to provide a subsidy of Rs 100 per month per agricultural consumer).

The process described so far is for the approval of cost and sales estimates of the distribution company. After the end of the financial year, as mentioned before, the company will return to the state ERC with the actuals of its performance for the year. The process of true-up then begins wherein the state ERC asks for justification of any deviation from the approved performance from the distribution company.

It is during the true-up process that normative parameters play an important role, since any deviation of the company from the parameter set by the state ERC results in gains or losses. For example, the O&M expenses are considered a controllable parameter by the Maharashtra state ERC and hence, if the company is able to exceed the target (keep the loss level below the norm) then there is a gain, and if it cannot meet the target (loss levels are above the norm) then there is a loss. The gains and losses are to be split between the company and its consumers based on the proportion decided by the state ERC.

The difference between the total revenue required and the total revenue earned is the ‘revenue gap’ (see Box 7.5 for more details). This revenue gap would be added to the ARR for next year and will be recovered through consumer tariffs.

Box 7.5: Revenue gap

Let us now assume that the performance of our distribution company is as shown in Table 7.9.

Table 7.9: ARR as approved by the commission and actuals claimed by the DISCOM

Particulars

Approved

Actuals

Total ARR (Rs crore)

2779

3000

Of which: O&M Expenses (Rs crore)

400

621

Let us also assume that the actual sales of the distribution company are as shown in Table 7.10.

Table 7.10: Sales of distribution company

Source (Table 7.9 & 7.10): Prayas (Energy Group)

Thus, two things have happened to our distribution company: (1) it has spent more money than approved (increase in O&M expenses), and (2) it has not managed to recover enough revenue. We can see that the distribution company exceeded its approved O&M expenses and spent an extra Rs 221 crore during the year. Thus, actual O&M cost during the year was Rs 621 crore against the approved O&M cost of Rs 400 crore. Let us assume that since this is a controllable parameter, our ERC disallows this. Thus, our ARR after ‘true-up’ continues to be Rs 2779.

However, there is still the Rs 345 crore which the distribution company could not recover from its consumers due to lower sales. Let us assume that our ERC decides that this was beyond the control of the distribution company. Thus, the ERC decides that this shortfall of Rs 345 crore needs to be recovered. This Rs 345 crore is then the ‘revenue gap’ of the distribution company and will be added to its ARR for the next year and recovered from consumers through an increase in tariff.

7.3.2 Some more on distribution tariff Fuel surcharge

As explained above, distribution companies recover revenue from consumers through tariff approved by the state ERCs based on anticipated costs for the year. However, there are often deviations between the approved costs and actual costs. Some of these expenses are reconciled at the end of the year before the state ERC and recovered in subsequent years from consumers. However, for deviations occurring due to a difference in power procurement costs (which account for 75% of the expenses of distribution companies), it is not always practical to wait for the annual reconciliation process.

This is because the generation company is paying the fuel supplier in advance and needs working capital that can support the fuel stock for a certain period. In such a case, the distribution company needs to pay the generation company on a monthly basis. In order to enable periodic revenue recovery to address cost variations during the year, many distribution companies levy a fuel surcharge in consumer bills. This charge is marked over and above the base fixed and energy charges, is collected on a per unit basis every month, and usually revised every quarter. The fuel surcharge is known by different names in different states. For example, it is referred to as the Incremental Power Purchase Cost in Himachal Pradesh and Uttar Pradesh, as Fuel Adjustment Charge in Maharashtra, and as Fuel Cost Adjustment in Madhya Pradesh, Karnataka, Punjab and Kerala.

The revenue to be recovered from the surcharge is typically estimated as a sum total of the deviation between approved and actual power procurement costs. The rate is estimated by dividing the revenue to be recovered by the total sales incurred by the distribution company in that quarter. ‘Fuel surcharge’ is a misnomer since in practice, in some states, the surcharge compensates not only for deviation in fuel expenses but also other power procurement and distribution expenses.

Regulatory asset and liability

As explained above, the tariff is supposed to be set by the state ERC in a manner that allows for full cost recovery of approved costs. Additionally, any increase in costs is met through an increase in tariffs. However, if in any year the ERC considers the required tariff increase to be too high (a ‘tariff shock’ in regulatory jargon), it may defer part of the recovery to future years. This deferred amount then becomes an asset for the company which is recovered over time. During this period, the company is entitled to recover the carrying cost (interest charges) on this amount. Both the asset and the carrying cost is recovered from the consumers through tariff over the years. Such an asset is called a ‘regulatory asset’. It is similar to a revenue gap in that it too is the difference between the revenue required and the revenue allowed to be recovered through tariff. Whereas the revenue gap (or surplus) is calculated every year and is usually recovered in one year, the regulatory asset is often so large that it needs to be recovered over multiple years.

It is worth noting that in the past, regulatory assets have been used to avoid politically unacceptable tariff increases. The reform measures of the last decade have strongly discouraged such a practice and the National Tariff Policy clearly states that ‘the facility of a regulatory asset has been adopted by some Regulatory Commissions in the past to limit tariff impact in a particular year. This should be done only as a very rare exception in the case of natural calamity or force majeure conditions. A regulatory liability is a mirror image of the regulatory asset in that it is akin to taking a loan from consumers.

Both regulatory assets and liabilities, are adjustment mechanisms that try to reduce the tariff shock or the cash flow problem of the company. These can be very important and can have a sizeable impact on the actual payment to be made by the consumer.

Time of day tariff

There has been a move towards making the retail price of electricity (tariff paid by the consumer) more reflective of the costs of generation. It is argued that in the traditional system, the consumer demand is fluctuating, increasing during certain hours (‘peak hours’) and falling otherwise. The supply has to be planned so as to follow the demand. However, tariffs are fixed. Thus, even during the hours of the day when electricity is more expensive, or months of the year when it is cheaper, the consumer pays the same amount per unit. Economists claim that this tariff structure does not provide the right signals to the consumer, leading to inefficient use of resources in building more ‘peaking plants’.

It is also claimed that if the tariff were changed (say every hour) to reflect the real-time cost of procuring that power in the wholesale market, then consumers would be incentivised to move their consumption from peak to off-peak hours. This would help ‘flatten’ the load curve. Such ‘time-varying electricity prices’ are commonly used, but not in their extreme version of ‘real-time pricing’ (varying every hour). For example, many distribution companies in the US have Critical Peak Pricing (CPP) programmes where consumers have to pay a higher price for peak power during certain time periods in summer.

Similarly in India, the Time of Day (ToD) tariffs have been implemented to incentivise High Tension (HT) consumers to move their consumption from ‘peak’ to ‘off-peak’ hours. Peak time usage is charged more and night time usage is offered at a concessional rate. The difference in the tariff for these two periods can be as high as 25% of the base tariff.

Power factor penalty / Incentive

As we know, a low power factor (PF) introduces a large reactive current and hence increases T&D losses, and also suppresses generation (reduces the output of a generation plant). Traditionally, HT industries with a low PF are penalised, and in many states incentive is offered for improving the PF beyond 90%.

7.3.3 Transmission tariff

The transmission tariff is similar to that of generation but is relatively simpler to understand. The capital cost, transmission losses and transmission system availability are the three critical factors for a transmission utility. The normative availability of the transmission lines is 98% and certain commissions provide an incentive to transmission companies if they exceed this percentage. If you look at the ARR of a transmission company, you will recognise the components from Chapter 6.

The total ARR for the transmission company is the Total Transmission System Cost (TTSC).⁵ This TTSC is allocated amongst the users of the transmission system, called Transmission System Users (TSUs), based on their peak demand, i.e. the maximum quantity of power they will transmit using the system.

In our example, all the electricity purchased by our distribution company is from generating stations located in the same state. In reality, however, it is possible that distribution companies purchase electricity from generating stations located in other parts of the country as well. In that case, in addition to the intra-state transmission tariff, the distribution company will also pay the inter-state transmission tariff. The inter-state transmission tariff is determined by the Central Electricity Regulatory Commission (CERC) based on a different method known as the ‘Point of Connection’ method.

Box 7.6: Transmission Tariff

In our example, we will assume that there is one transmission company with a TTSC of Rs 400 crore. Let us assume that there are two distribution companies in our state, and let us further assume that they are identical. Thus, they have the same demand and will each use the distribution system to transmit equal amount of electricity. Thus, the TTSC is split evenly between these two distribution companies. Our distribution company then will have to pay Rs 200 crore as transmission charges for using the inter-state transmission system.

7.3.4 Generation tariff

As discussed in Chapter 6, the generator will approach the regulatory commission with a petition for approval of its capital costs and for the determination of the cost of power from its station (generation tariff). This should ideally occur a few months before the start of the next financial year. Let us suppose that the generator approaches the commission for the approval of the capital cost and determination of tariff in December for the next financial year beginning April of the next year. From Chapter 6, we know the components of fixed cost and variable cost.

Availability, PLF and generation

Availability and Plant Load Factor (PLF) were explained in Chapter 3. The generation station has to propose the amount of time it will be available (as a percentage) in the year. The station proposes a PLF as well. However, the actual PLF will depend on how much the station actually ends up generating, which itself is a function of its fuel cost and the amount of electricity required by the distribution company it has signed the PPA with. The availability of a plant is also targeted at a certain percentage by the ERC regulations for recovery of fixed costs.

Auxiliary consumption is the amount of generated electricity that is consumed by the auxiliary equipment of the generating station as well as the transformer losses within the station. Using the proposed PLF, the generating station projects the gross generation, using the following formula:

Using the auxiliary consumption, we get the net generation, using the following formula:

Net Generation = Gross Generation×(1-Auxiliary consumption (%))

The net generation is the generation that will leave the generating station and is also referred to as ex-bus generation.

Variable cost

As discussed in Chapter 6, the variable cost is incurred only when actual generation happens and hence, is calculated in Rs per kWh. The generating station will provide projections of its Station Heat Rate (SHR), which is the amount of heat needed by the station to produce 1 unit of electricity, as well as the Gross Calorific Value (GCV) of its fuel, in this case coal. The GCV, as you will know from the Annexure to Chapter 2, is the heat released when 1 kg of fuel is burnt.

We use these values to calculate the projected Specific Coal Consumption, using the following formula:

This is the amount of coal that needs to be burnt to generate 1 unit of electricity. We then need to calculate the cost of this coal. For this we use the following formula:

This is the amount of money it will take to generate one unit of electricity from our generating station using coal. We will assume that coal is the only fuel used by our generating station (usually there is some oil consumed in coal based thermal power plants, though it is in very small quantities and insignificant financially), and thus, this cost of coal consumption will be our variable cost as well.

This cost of coal consumption/variable cost is the cost of generation per unit. The distribution company (and hence consumers) pay for the total cost of generation, including auxiliary consumption, even though they only receive the net generation from the station. Thus, the variable cost at the generating station end (or at ‘bus bar’) will be:

The generating station will receive the equivalent of its net generation in a year multiplied by the variable cost from the distribution company. Also fuel surcharge payments need to be considered here. Hence, if the generating station generates 2350MUs at 85% PLF, then the variable charge payable by the distribution company to the generator will be:

Fixed cost

In Chapter 6, we learned the components of the fixed cost. The fixed cost which is proposed by the generating station will be reviewed by the commission to ensure that the expenses are prudent.

Box 7.7: Stylised example for generation tariff

Here we look at the cost determination process of Power Plant 1. We already know from our continuing example that our distribution company has a PPA with Power Plant 1. We also know that for 2018-19 its fixed cost is Rs 150 crore and its variable cost is Rs 1.64 per unit. How were these figures arrived at? Let us find out.

Let us assume that the generator approaches the commission with the proposed costs listed in Table 7.11 for the coming financial year 2018-19:

Table 7.11: Proposed costs for the generator

Particulars

Units

Proposed

Capacity

MW

500

Availability

%

85%

Plant Load Factor (PLF)

%

85%

Auxiliary Consumption

%

8%

Gross Generation

MU

3723

Net Generation

MU

3425

Gross SHR

kcal/kWh

2350

GCV of Coal

kcal/kg

3800

Price of Coal

Rs/MT

2500

Fixed Cost

Rs Crore

150

Source: Prayas (Energy Group)

Our Power Plant 1 has a capacity of 500 MW. Using the formulas in the text, we get:

Gross generation of 3723 MUs at 85% PLF

Net generation of 2350 MUs at auxiliary consumption of 8%

Specific coal consumption of 0.62 kg/kWh

Cost of coal consumption of Rs 1.55/kWh

Energy charge of Rs 1.68 per unit⁶

Variable cost of Rs 576 crore

The above calculations are summarised in Table 7.12.

Table 7.12: Specifics of a 500 MW power plant

Calculated particulars

Units

Value

Specific Coal Consumption

kg/kWh

0.62

Cost of Specific Coal Consumption

Rs/kWh

1.55

Energy Charge at Bus Bar

Rs/kWh

1.68

Variable Cost

Rs crore

576

Source: Prayas (Energy Group)

In our example here, we have taken the fixed cost as a total and not broken it down into its component parts. The fixed cost for our Power Plant 1 is Rs 150 crore.

Proposed in the petition and approved in the order

Till now, we have seen how the generating station proposes to function in the coming year-how much it expects to generate and at what costs. As in the case of distribution and transmission, the commission will deliberate on the proposal of the generating station, including checking the costs to make sure they are prudent as well as in line with current prices. They will also hold public consultations for this purpose. These deliberations by the commission will culminate in an order. This order will give the approved figures for how the generating station is expected to operate in the coming year and should also include the reasons for the approval/disapproval/change in the costs and figures.

Normative parameters and true up

At the end of the operating period (a year, in our example), the generating station will approach the commission for a ‘true-up’, wherein deviations in the station’s performance from the limits set in the commission’s order are discussed and deliberated.

Normative parameters play an important role during true up. For example, most ERCs specify the normative availability of the generation plant. The generation plant will be able recover its full fixed cost for the year only if it is able to show this availability. If it falls short of the normative availability, its fixed cost will be reduced in proportion.

Box 7.8: Stylised example for generation tariff … continued

Continuing our example, let us assume that the proposed parameters of the petition and the approved parameters of the commission’s order are as listed in Table 7.13.

Table 7.13: Proposed and approved parameters of generating station

Source: Prayas (Energy Group)

As can be seen from the table, the generating station had proposed a variable charge of Rs 1.68 per unit and a fixed cost of Rs 150 crore. Now, let us see what the commission decided. We can see that the commission has reduced the auxiliary consumption of the station. This gives us Rs 150 crore as fixed cost and Rs 1.64 as the variable cost, and these approved costs are what the distribution company will pay. The generating station has to now try and ensure that it operates within these limits as ordered by the commission.

Let us assume that the generating station comes back with the actuals recorded in Table 7.14.

Table 7.14: Actuals as claimed by the generating station

Source: Prayas (Energy Group)

As we can see, the generating station could not stay available for the determined time; instead of 85% it was available only for 80%. As mentioned above, the availability of the generating stations is set at a normative target by the ERCs. For our station it was 85%. Failure to meet this target means that the generating station will not be able to recover its full fixed cost, and instead its fixed cost recovery will be reduced pro-rata. Thus, instead of Rs 150 crore, Power Plant 1 will only be able to recover Rs 141 crore this year.

7.3.5 More details on generation tariff

Single part vs two part tariff

The simplest form of tariff is the single part tariff, wherein there is a single tariff to cover both fixed and variable costs. The variable cost (usually in Rs per unit) is converted into monetary terms (Rs) by determining a normative generation level for the generating station (certain MUs). The sum of the fixed cost and variable cost is then divided by these MUs to arrive at a single Rs per unit rate. This tariff has built-in incentives and disincentives. If there is a shortfall in meeting the target generation, then there will also be a shortfall in recovering the fixed cost. If, however, the generating station exceeds the target generation then there will be a surplus.

The NTPC charged at a single part tariff till 1992. The single part tariff created a lot of problems. The State Electricity Boards, which were purchasing electricity from NTPC stations, were unwilling to buy power at night as they had sufficient generation during night hours. Since in a single part tariff the only way to earn revenue is to operate, the NTPC did not reduce its power generation at night. This resulted in excess generation, high frequency and even grid instability during the night hours. Let us try and understand the problems prior to conversion to an Availability Based Tariff (ABT) a little better. Let us assume there are two SEBs, both having 50% allocation from an NTPC plant. Both SEBs take their share during 12 hours of daytime, but during the night SEB A avoids taking its share and only SEB B takes all the remaining power. Thus, SEB A is buying 25% of the power, while SEB B is buying 75% of the power. Since, this was a single tariff, SEB B paid 75% of the fixed cost while getting only 50% of capacity benefit during the most required peak period (i.e. day time). This was unfair and no SEB was willing to purchase electricity from NTPC during the night.

These problems were resolved by converting the single part-tariff into a two-part tariff. The two part tariff for a generating plant is simply recovering the fixed costs and variable costs separately with two different charges.

Availability Based Tariff (ABT)

The two-part tariff for generation companies is called the Availability Based Tariff (ABT). It is called availability based since the fixed cost recovery is tied to the availability of the plant. ERCs set a norm for availability. If the actual availability is more than the norm, the generation company gets an additional payment. If the availability is lower than the norm, then the fixed cost payment is proportionately reduced. The ABT changes the incentive for generation companies away from generation to availability. The ‘fixed charge’ or ‘capacity charge’ is calculated by dividing the monthly fixed cost by the plant availability and is in Rs per MW per month. In addition, this involved allocating the fixed cost amongst the buyers based on the MWs allocated to the SEBs. This means that payment for the fixed cost is based on the right to use the plant (availability) irrespective of whether the distribution company decides to buy power or not, and the variable cost for each unit of electricity purchased is separate.

Scheduled generation and unscheduled interchange (UI) charges

In the situation mentioned above when the NTPC was charging at a single part tariff, the SEB’s unwillingness to take NTPC power at night and the NTPC’s unwillingness to reduce generation during night hours was only half of the problem. While the two-part tariff may have redesigned incentives to avoid over-generation when not needed, there was also the problem of over-drawal (overconsumption) and under-drawal by SEBs. Basically, the SEB’s would draw more power than their quota from the NTPC to reduce load shedding during peak hours, but take less than their quota during off-peak hours. This behaviour of the SEBs led to frequency deviations, grid instability and disputes. Thus, another set of incentives and disincentives were needed for better system operation and grid discipline.

The second part of the ABT tariff is the ‘variable charge’ or ‘energy charge’ which is to compensate for the fuel cost of generating electricity. However, under the ABT mechanism, this is not based on the actual electricity generated by the generation company but on the scheduled generation. Generation companies have to inform their availability for the next day to their LDCs. They are in turn given a schedule of generation, i.e. they are told how much to generate and when in the following day. Even if there are deviations from this schedule, the generation companies are paid an energy charge based on the scheduled generation by the SEBs. The deviations are priced according to the system conditions at the time. This payment could be negative (i.e. a penalty to be paid by generators) if the generation company generated less than scheduled. This payment for deviations is called Unscheduled Interchange (UI) charge and is the third component of our ABT tariff. Thus, there are three components to our ABT tariff: (i) fixed charge linked to availability, (ii) energy charge linked to scheduled generation and (iii) UI charges for payment for deviating from the schedule.

The UI charges are also paid by/payable to the distribution company (and SEBs) for any over-drawal or under-drawal. The ABT tariff and UI charges have hence helped to improve grid discipline. Bringing in the ABT also introduced a proxy spot market for power. Needy SEBs drew more while less needy ones refrained from drawing their share in times of shortage. They were charged and compensated accordingly.

Box 7.9: Tariff for renewable energy projects

Renewable energy projects are single part tariffs and their tariff determination follows a different process. In order to promote renewable energy projects, governments across the world have used different incentives. These broadly include (i) providing a direct subsidy for the establishment of the project, (ii) paying a pre-decided subsidy per unit at the time of sale, (iii) Having a renewable energy purchase obligation, i.e. obligating utilities are to purchase a part of their power from renewable energy sources, and (iv) procuring power at a preferential feed-in-tariff.

In India, type (iii) and (iv) are practiced. The E Act mandates ERCs to impose minimum renewable energy purchase obligations (RPOs) on the DISCOMs. The RPOs notified by ERCs have been an important regulatory instrument behind the growth of the renewable energy sector.

In terms of tariff, the renewable energy contracts can be under Section 62 or Section 63 of the E Act (competitive bidding). Under Section 62, the tariff paid to renewable energy generators is the ‘generic tariff’ or preferential feed-in-tariff decided by the state ERC. Till 2017-18, the ERCs determined the generic tariff based on CERC benchmarks for renewable energy generation costs. Thus, the distribution company would sign a PPA with a renewable energy generator, but the tariff would not be negotiated and would instead be the ‘generic tariff’.

Till about 2016, almost all utility procurement of wind power by states was carried out at the SERC notified feed-in-tariffs. This was in line with the tariff policy recommendation in 2006 to procure renewable energy at preferential tariffs. It was expected that renewables will take time to compete with conventional power. However, since 2017, competitive bidding has been introduced in wind power procurement and most DISCOMs are procuring wind power through bidding.

Like the wind sector, solar procurement in its very initial stage was based on Feed-in-Tariffs (FiTs). However, the early success of the reverse auction bidding introduced under the Jawaharlal Nehru National Solar Mission (JNNSM) proved to be crucial. Since the launch of the JNNSM in 2010, the solar PV sector has been in an extremely dynamic phase of evolution both with regard to technology and prices, and nearly all states are prudently sticking to competitive bidding for solar power procurement.

7.4 Consumer tariff

In this section we look at trends in overall tariffs as well as the tariff for certain categories of consumers, namely agricultural, industrial and residential consumers.

7.4.1 Reduction in cross-subsidy

Historically, all tariffs were set taking into account social considerations and the perceived capacity to pay, with agricultural and small household consumers being charged a low tariff. However, as industry tariffs increased beyond the cost of captive generation, the industry started voicing its concerns. At the same time economists started putting together evidence to show that cost based tariffs are more efficient. This has led to intense debate and legislation.

The ERC Act of 1998 specified that ERCs should progressively remove cross-subsidies and set all tariffs equal to the average cost of supply. Although it was one of the principle components of the Act, it was not fully implemented due to opposition from many states. The next legislation, the E Act of 2003, has empowered large consumers to procure power from the suppliers of their choice (by allowing open access, trading and freeing up captive generation). This has put some additional pressure on the DISCOMs and ERCs to reduce emphasis on social considerations and accord more importance to economic considerations.

Figure 7.6: Movement of tariff in Maharashtra from 1975 to 2003

Source: Prayas compilation from MSEB annual reports and regulatory orders

Figure 7.6 compares the ACoS with the ABR in nominal terms for agricultural and industrial consumers in Maharashtra, from 1975 to 2003. It can be seen that the difference in the cost of supply and agricultural tariff widened in the 15 years from 1985 to 2000. It is essential to note that after the Maharashtra ERC was established, the true agricultural consumption was revealed to be much lesser than what was actually claimed (see Section 7.4.2 on agricultural tariff below for more details). The jump in the year 2001 is the combined result of reassessed consumption (towards the lower side) and an increase in tariff by the MERC. Thereafter, the increase in agricultural tariff is largely due to tariff rationalisation brought about by the MERC. Since 2000, the industrial tariff has steadily declined while the agricultural tariff has steadily increased till 2003.

Similar trends are seen in many other states. In 1997, during the initial years of reform, domestic and agriculture tariffs were considerably low - only 50% and 10% of the average cost of supply. Once the reforms began, tariff of domestic and agriculture consumers went up, but still remained below the average cost of supply. In 2013, domestic and agriculture tariffs were 50% and 30% of the average cost of supply. Commercial was 30% higher and the industry tariff nearly equal to the average cost of supply.

Thus, there has been a move to reduce cross-subsidy to make tariff more in line with the cost of supply. This process is known as ‘tariff rationalisation’.

7.4.2 Agricultural tariff

Agricultural consumers have been the most subsidised class of consumers. Agricultural tariffs as well as agricultural consumption have been the most controversial aspects of the Indian power sector.

Let us understand the background of the flat tariff. In the mid-1970s, some state utilities were finding it difficult to maintain meters, note meter readings, and bill the dispersed agricultural consumers. These states introduced a flat tariff linked to the power rating of the pump, and removed the meters. At that time, the flat tariff was comparable to the metered tariff (based on the average pump usage), and agricultural connections were few. Hence, it did not have any immediate adverse impact.

Farmers appreciated this move because it did away with the uncertainty of electricity bills and the possibility of high bills due to wrong meter readings. Several states adopted this method. Over the years, the flat tariff declined, pump usage increased, and the costs of the utilities increased rapidly. At the same time some states also started supplying free electricity to agricultural pumps. As a result, the difference in the cost of supply and the tariff for agricultural consumers increased so much that serious financial problems arose.

Between 1974 and 1997, electricity consumption in agriculture grew by an average of 12% every year and its share in the total electricity consumption rose from 11% to 27% during the same time. With it the electricity subsidy required also increased. In 2012-13, the erstwhile Planning Commission pegged the total subsidy requirement of DISCOMs for agriculture at around Rs 62,000 crore for that year. Electricity to agriculture is subsidised not only by the state governments, but also by commercial and industrial consumers who pay tariffs higher than the cost of supply through cross-subsidy. While the entire subsidy to agriculture is supposed to be met by government and cross-subsidy, often some part of it is not covered by either, which results in a loss for the DISCOM.

Figure 7.7 shows the average tariff applicable to the farmers in different states in the period 2012-2014, as well as the level of metering of agricultural connections in these same states. To get a sense of the level of subsidisation, it is important to note that the average cost of supply of many of these is more than Rs 6/kWh as of 2017.

Figure 7.7: Average electricity tariff charged to farmers and the percentage of metering in some states

Source: Derived and compiled by Prayas (Energy Group) from data in various state tariff orders and petitions.

The measures of metering agricultural connections and increasing agricultural tariff have been proposed by the central government to reduce the subsidy burden and provide a more accurate assessment of consumption. In fact, 100% metering of all electricity consumers including irrigation pump sets has been suggested by multiple official agencies in the past two decades, is stipulated in the Electricity Act 2003, and is one of the repeated directives of many SERCs.

However, as seen in Figure 7.7, in the major agricultural electricity consuming states, only 27% of agricultural connections were metered. Among these, almost all agricultural connections in states providing free power, such as Punjab, Andhra Pradesh and Tamil Nadu, are unmetered. Agricultural tariff was increased in some states but not by much. However, many states also started supplying ‘free power’ to farmers. Tamil Nadu has been doing so since the 1990s, while Maharashtra and Andhra Pradesh did so more recently.

As a result of the de-metering of the agriculture sector, the actual electricity consumption by this sector is unknown. Even where meters are installed, there are issues with the quality of meter readings. Hence, agricultural electricity consumption has to be estimated. Different states, and sometimes even different DISCOMs within the same state, use different estimation methods.

Many have argued that agricultural electricity consumption is overestimated by the DISCOMs to project low distribution losses and claim higher subsidy. Why would the DISCOM do this? The distribution loss is the energy for which the DISCOM has incurred expenses, but has received no revenue. So it results in a financial loss to the DISCOM, which will either have to be borne by the DISCOM or recovered from consumers as tariff. Some states, such as Maharashtra, Tamil Nadu and Punjab, have distribution loss targets that require any loss higher than the targets to be borne (partially or fully) by the DISCOM. On the other hand, any financial losses due to agricultural sales have to be reimbursed by the government, or can be passed onto consumers.

After the ERCs were established from 1998 onwards, successive studies on agricultural consumption were conducted in different states. These studies revealed that agricultural sales were overestimated in many states and consequently, agricultural sales and transmission and distribution (T&D) losses of state electricity boards were restated by SERCs. This resulted in agricultural electricity sales across the country actually declining from 27% in 1997 to 22% in 2001-02, whereas the T&D losses increased from 23% to 33% during the same period. Table 7.15 gives the agricultural sales and distribution losses before and after restatement for some states.

Thus with the introduction of ERCs there has been increased scrutiny of the agricultural sales estimations and T&D losses of DISCOMs, but the problem still persists.

Table 7.15: Restatement of agricultural electricity sales and distribution loss

Source: Derived and compiled by Prayas (Energy Group) from data in various state tariff orders and petitions

In addition to overestimation and metering issues, poor quality of supply is a major issue in agricultural electricity supply. To minimise the commercial losses, utilities are choosing to limit the power supply to rural, especially agricultural feeders, or to provide them power when the cost of supply is low (such as off-peak time). Thus, the financial problems of DISCOMs also affect farmers who have to make do with poor power supply and service quality.

As a result, the hours of supply, the quality of supply, and the estimation of agricultural consumption are still contentious issues in most states. Consumption estimation, tariff hike and government subsidy to agricultural consumers are likely to remain much debated issues for some time to come.

7.4.3 Industrial tariffs and open access

Commercial and low voltage (LT) industry tariffs are similar in nature to residential tariffs. The LT industry receives power at 415 volts. If the demand is higher than a specified limit, the industry is required to receive supply at 11 kV or higher voltage and is then classified as an HT industry.

The number of HT industries in a state may be small but their consumption is fairly high. The high consumption compels HT industries to look out for lower cost options. The reliability of supply is also very critical for many industries. In the past, industries for whom supply quality and reliability was crucial would opt for captive power plants, even if these were more expensive than the DISCOM rates.

While earlier industries would have to take permission from the DISCOM or the ERCs to set up a captive power plant, the E Act did away with this requirement. In addition, as mentioned before, the E Act mandated open access for any consumer with a connected load of 1 MW or higher. These consumers can choose to buy power from any supplier other than their DISCOM. They however use the wires of the DISCOMs to get this supply. Open access can be opted for short, medium or long term and for meeting either the full or partial demand. Consumers who opt for open access need to pay the following charges:

Wheeling charge: Since these consumers use the wires of the DISCOM and transmission company for getting their supply, they need to contribute towards the fixed costs of these networks. The ERC determines the wheeling charges to be paid by these consumers for using the distribution and transmission wires and notifies them along with the tariff schedule. These charges are based on the voltage level at which the consumer is connected.

Cross-subsidy surcharge: Since it is large consumers who have the option of open access, the DISCOM loses cross-subsidy if these consumers migrate to other sources. In order to compensate the DISCOM for the loss of cross-subsidy, the ERCs impose a cross-subsidy surcharge for such consumers. The National Tariff Policy 2016 specified a formula for calculating this surcharge and guidelines to ensure that this surcharge does not exceed 20% of the tariff applicable to the category of consumers seeking open access.

Additional surcharge: In recent years, DISCOMs are witnessing surplus baseload capacity. In many states, ERCs have introduced an additional surcharge on open access consumers to compensate the DISCOMs for capacity that is underutilised due to fall in demand, which is attributable to loss of sales via open access. The National Tariff Policy 2016 allows for recovery of such additional surcharge only if it is conclusively proved that there is an unavoidable burden on the DISCOM to bear fixed costs of capacity that is now stranded but was contracted earlier to meet its supply obligation.

In addition to the above charges, open access consumers like all other consumers are also required to pay electricity duty. Further, these consumers are also subject to the renewable purchase obligation requiring them to procure a certain amount of their energy requirement from renewable energy sources. The obligation is specified by the concerned SERC.

7.4.4 Residential tariff

Electricity use in Indian households has increased 50 times since 1971 and has tripled since 2000. The percentage of households with access to electricity has increased from 55% in 2001 to more than 80% in 2017, and residential electricity consumption growth presently is higher than that of industrial, commercial and agricultural sectors. Rapid electrification, urbanisation, increasing incomes and technological development will likely see households buying more appliances and consuming more electricity.

The residential sector already uses 25% of the country’s total electricity consumption, even though there are many non-electrified households and power cuts are frequent. In 2014, an electrified Indian household consumed about 90 units of electricity per month on an average. This is enough to run four tube-lights, four ceiling fans, a television, a small refrigerator, and small kitchen appliances.

There have been many efforts to provide poorer households with subsidised/free connections. Household consumers desirous of using only a single light point are offered a low fixed tariff and connection charges are usually waived. Many state and central sector schemes have offered such connections. Some states also provide direct subsidy to poor residential consumers, in a manner similar to the agricultural subsidy.

Another mechanism used to subsidise low-consuming houses is the telescopic tariff. Here, the tariff is increased with increasing energy consumption. The energy charges are calculated ‘telescopically’ (the first 50 units are charged at a low tariff, the next 50 at a higher tariff, and so on). As a result, high consumers of power end up paying a high tariff. This is said to be against ‘economic’ logic, but it has a social logic. Our example had telescopic tariffs for residential consumers. Hence, households were paying Rs 3.55 per unit for the first 50 units, Rs 4.57 per unit for the next 50, and Rs 5.58 per unit for all units above 100. Figure 7.8 and Figure 7.9 give the telescopic energy charge for residential consumers in 2012-13 and 2017-18 for Maharashtra and Madhya Pradesh respectively.

Given the increase in migration of high paying consumers, DISCOMs and ERCs have also been looking to provide cross-subsidy only to their poorest consumers. For example, the Maharashtra state DISCOM’s average cost of supply is Rs 6.5 per unit and hence, only consumers with consumption below 100 units per month are subsidised, while the rest are actually subsidising others. A similar trend is seen in Madhya Pradesh with its ACoS at around Rs 5.7 per unit.

Figure 7.8: Energy charge (Rs/kWh) for Low Tension (LT) residential consumers for MSEDCL, Maharashtra

Source: MERC tariff orders for respective years

Figure 7.9: Energy charge (Rs per kWh) for Low Tension (LT) residential consumers in Madhya Pradesh

Source: MPERC tariff orders

Apart from energy charges, household consumers also have to pay other charges such as meter rent, fixed charges, etc. In some cases, a minimum threshold for the bill is also set. The fuel surcharge and taxes are additional. There are some other charges that are paid by residential consumers and these are explained below.

Minimum charge: If a house is locked and does not use any electricity, then the utility cannot recover its fixed cost through the energy charge. Some cities have a large number of such empty dwellings. Hence, tariffs have a bottom line called ‘minimum charge’. Minimum charge is calculated in such a manner that consumers in inhabited houses would have a consumption level which would exceed the bottom line, and therefore would not be adversely affected by such a charge. Minimum charge is also used in states with poor access to recover some amount from all consumers.

Meter rent: The meter is the boundary between the consumer and the utility. Either the consumer or the utility can install the meter. When the meter is owned by the utility, it is allowed to charge either a meter rent or take a meter deposit.

Security deposit: The consumer uses the electricity first and pays for it later. As a security for the bill, the distribution company takes an advance amount from the consumer, which is known as a ‘security deposit’. The deposit is refundable and the distribution company has to pay interest on this amount to the consumer (called ‘interest on consumer deposits’). If the consumption of a consumer increases, the utility is authorised to collect a bigger deposit from that consumer.

In this chapter we have seen the different aspects of tariff, the most common interface between the consumer and the utility. We have seen that tariff depends on the utility’s costs, which in turn are dependent on the utility’s planning and operational decisions. Tariffs of different consumers depend on the tariff philosophy adopted by the ERC. Social, political and economic considerations continue to feature in the tariff philosophy, even as economic considerations are starting to gain an upper hand.

Endnotes

¹ The credit for this compromise and the ‘rate of return’ regulatory model goes to Samuel Insull, one time secretary to Thomas Edison and founder of the Commonwealth Edison Company, which still supplies electricity to the city of Chicago and surrounding areas. The compromise is also known as the Regulatory Bargain or the Regulatory Compact.

² Another concept associated with cost-plus regulation is ‘regulatory lag’. The tariffs in a cost-plus system have to reflect the costs incurred by the company plus the profits. However, the tariff is fixed in advance and is not continuously adjusted to reflect the actual costs of the company. Thus, the regulated tariff adjusts with a lag, and this allows the company to make a profit by cutting costs (becoming more efficient) before the next tariff adjustment. Of course, regulatory lag was not intended to provide an incentive for efficiency. Its applicability to the Indian context is also debatable.

³ The phenomenon of ‘gold-plating’ is well established in regulatory economics and is known as the Averch-Johnson Effect. The idea was put forth in Harvey Averch and Leland Johnson’s 1962 paper and states that because profit varies directly with base (capital), companies tend to substitute excess capital for other inputs.

⁴ The levelised tariff is defined as the ratio of the net present value of total capital and operating costs of a plant to the net present value of the net cost of electricity generated by that plant over its operating life. The discount rate used for calculating the net present value is a crucial variable and is notified by the Central Electricity commission every six month for evaluating bids opened in that period. www.cercind.gov.in/escalation_rates.html

⁵ In the case of multiple transmission licensees, such as in Maharashtra, the Total Transmission System Cost (TTSC) is the sum of the ARRs of each transmission licensee.

⁶ You can think about this in another manner. If we take the variable cost as is (without auxiliary consumption), then it is the cost of generating one unit of electricity. Electricity generated by the station is given by the Gross Generation, which is 3723 MUs. This will cost the distribution company Rs 576 crore. However, the distribution company is actually receiving the Net Generation of 3425 MUs since some electricity is being consumed by the station (auxiliary consumption). Thus, the real Variable Cost to the distribution company of buying electricity from this generating station is Rs 576 crore divided by the Net Generation, i.e. Rs 1.68 per unit (=576 x 10/3425).

8 : Planning - Why, What and How?

The last three decades have witnessed many changes in the Indian power sector in policy, institutional structure and ownership. With many private companies in generation and distribution and some in transmission, the Indian electricity sector is no longer entirely owned and operated by the government. Market considerations play a role in the establishment of generating stations and the choice of the source of power supply on the part of big consumers. In such a situation, is there any role for planning, and if so, what is it? We believe that electricity is a basic necessity and equitable access to this resource can catalyse development. There are huge disparities in access and many actors in the sector, involved in diverse and often competing activities. A comprehensive approach to planning the sector is the only way to ensure optimal use of scarce resources and good quality affordable access with minimum social costs.

8.1. Does planning matter for electricity?

For the first time in its history, the Central Electricity (CEA) reported that there would be a power surplus in the country in the year 2016-17. The CEA’s annual Load Generation Balance Report released in May 2016 predicted a small electricity surplus in 2016-17, amounting to 1.1% in energy and 3.1% in peak demand. According to this report, only half the states were to experience shortages. The next two annual reports in 2017 and 2018 also predicted small power surpluses for the subsequent years. Some states like Gujarat, Maharashtra, Punjab, Haryana and Madhya Pradesh reported actual surpluses varying from 20% to 30% in 2016. For a country which had been experiencing power shortages for many years, this was good news. Peak shortage was very high at 20% in 1993, reduced to 11% in 1998, and has been steadily reducing from 2014, when it was 4.5%. The CEA’s projection of power surplus has come close to truth, with the last two years (2017 and 2018) reporting a very low peak shortage of 2%. While this is a welcome development, will power surplus be an opportunity to provide quality access to all, or be a problem leading to increase in economic and social costs?

In 2014, India’s Planning Commission was dissolved. This institution had put out 12 five-year plans from 1951 onwards of which planning for the electricity sector was an important constituent. As we have seen in Chapter 5, the Indian electricity sector today is partly owned and operated by private companies. The state electricity sector is not vertically integrated, such that there are different companies responsible for generation, transmission and distribution. To some extent, generation capacity addition, distributed generation and bulk power consumption are driven by market or consumer preferences. In such a situation, is there any role for planning in the electricity sector?

This chapter underlines that there is indeed still a role for planning in the electricity sector, and explains why this is so, what the role of planning is, and how planning for the electricity sector is carried out in India.

Planning is preparation for tomorrow, based on past experiences and future aspirations. Power sector planning activity covers generation, transmission, distribution, end use efficiency, required fuels and the support systems (communication, people, buildings, and other facilities). Planners analyse the sector’s behaviour in the past and study the impact of external factors. These factors include economic growth, resource limitations, environment, weather, population growth, changes in consumer behaviour and technology innovations. However, planning is not just based on past trends, but also on the societal aspirations about the sector’s role in the years to come.

The importance of planning in the electricity sector is explained by the following factors:

Significant investment

To begin with, significant investments to the tune of a few lakh crore rupees are made every year in the electricity sector by the central government, state governments and private players. As per the India Energy Outlook prepared by the International Energy Agency in 2015, around 5 lakh crore rupees may be invested in the sector every year during the period 2015-2040. Even though there is a significant presence of private companies in the sector, even today, it is public investment that drives the sector. As seen in Chapter 6, in the period 2005-2015, public financial institutions and public sector banks contributed 86% of the lending to thermal generation projects. It is important that this investment is put to good use and brings positive development outcomes. Proper planning is crucial to ensure this, especially in a country like India with limited resources.

Long lead times and long life

Some important components of the power sector like generating stations and the transmission and distribution infrastructure have a long life of 50-75 years. While generating stations and the transmission system can be constructed in 5-10 years, distribution systems can be constructed in fewer years. Renewable plants and small generating stations can be set up faster than bigger generating stations and the transmission infrastructure, but again have a long life of 25-30 years. It is clear that it takes a long time for the investment to start yielding results and the components last for many years. Any wrong investment would be a waste of money and can even be a continuous drain on resources.

Minimising adverse impacts

The electricity sector - especially conventional power generation and transmission - has many adverse impacts on the livelihoods of affected communities, natural resources and the environment. But electricity consumption has a multiplier effect on the economy and can significantly improve quality of life.¹ Hence it is important to invest in electricity, but with prudence, to maximise positive development outcomes and minimise adverse impacts.

We believe that electricity is a basic necessity and equitable access to this resource can catalyse development. There are huge disparities in access even now. Many different actors are involved in diverse activities in the sector, often with competing interests. The cost of failure, due to reasons like wrong investment decisions or poor coordination between different actors, is very high, especially for resource poor countries like India. A comprehensive approach to planning for the sector is the only way to ensure quality and affordable access with minimum social costs.

Addition of coal power capacity after generation was delicensed in E Act, without ensuring sufficient coal production and transport is an example of planning failure. In the 11th plan period (2007-12), thermal power capacity addition was near target, whereas coal production very much short of it. In the 12th plan period (2012-17), thermal capacity addition exceeded target and today we have a stranded thermal capacity of around 40,000 MW. Other unfortunate examples of costly failures include gas based power plants lying idle due to shortage of gas² and hastily implemented power sector reforms in Odisha. Rural electrification programmes planned after 2005 are examples of initiatives with good intent and objectives. With better planning and coordination, the outcomes of these programmes would have been much better.

8.2. What is planning?

Planning for the electricity sector involves the identification of long-term investment options to ensure reliable power supply and meet the policy objectives at reasonable economic, social and environmental costs. In India, policy should be directed towards the reduction of poverty and the promotion of all-round development through affordable, equitable and continuous supply of quality electricity. This would need special attention towards meeting the basic electricity needs of all, providing electricity supply to all community services like drinking water facilities, health centres and street lights, ensuring sufficient electricity to small enterprises including agriculture, and promoting relevant big industry.

Figure 8.1 is a simple schematic which explains the rationale behind planning for the electricity sector. Indian planners often equate development with economic growth, which needs electricity supply as a major input. Many government plans and policies base their estimation of the electricity required for development and growth and its costs on the correlation between economic growth and the quantum of electricity generated.³ The harmful impact of the electricity sector on ecology (on people’s livelihoods, and the local and global environment) and the resulting negative consequences for development are neglected, and in any case are not easy to quantify.

Figure 8.1: Planning for the electricity sector - A simple schematic

Source: Prayas (Energy Group)

The planning process can be markedly improved by critically examining the links between the boxes in Figure 8.1. It is necessary to understand that each of these flexible links can be modified in a favourable fashion. Starting from below, how can there be maximum electricity supply with minimum ecology degradation? How can we change the energy supply options and ensure efficient use of electricity to minimise ecology degradation and its impact on development? How can economic growth be maximised with minimum electricity supply through relevant and efficient use of electricity? How can we achieve high development outcomes with minimum economic growth?

Once the energy supply requirements are worked out, a detailed planning exercise for the power sector should cover the following areas and develop different scenarios to account for the risks and uncertainties involved. It should also cover required support systems like communication, people and buildings, but we will limit our discussion to the following aspects:

Centralised generation, including fuel supply

Distributed generation

Demand side resources like energy efficiency and load management

Transmission and distribution

Based on time horizons, planning can be done on different time scales: long term (10-20 years ahead), medium term (3-5 years) or short term (from a few days to a maximum of one year ahead - also called operational planning). Results of the longer term planning processes constitute inputs to the shorter horizon planning and operational data is a major input to long term planning. In this book, we focus on long term and medium term planning.

8.2.1 Integrated Resource Planning - An ideal approach

An ideal, comprehensive planning approach should take into account the development mandate of the electricity sector and prepare an integrated plan considering all the four areas mentioned above. Integrated Resource Planning (IRP) is such an approach. IRP is a planning approach that considers both supply and demand side options to meet the requirement for a resource, while minimising the costs to the utility, government and society. Box 8.1 recounts a brief history of IRP.

Box 8.1: Brief history of Integrated Resource Planning

Integrated Resource Planning (IRP) originated in the US in the late 1970s in response to the many challenges facing the country’s electricity industry. These challenges included rising fuel costs, slowing economic growth leading to stagnation of electricity demand, excess power generation capacity, environmental regulations about air and water quality, and energy efficiency goals. IRP was an attempt to balance the conflicting demands of consumers (who wanted quality power supply without tariff increase), power utilities (which demanded tariff increase) and environmentalists (who demanded reduction of environmental impacts). Many electricity regulators mandated the IRP process, which was transparent and participatory so that conflicting interests were represented. The objective of the IRP process was to arrive at the least cost solutions to supply quality power to consumers.

IRP continued to be important even after deregulation, i.e. opening up of the generation sector of the US electricity industry in the late 1970s, which could be considered equivalent to reforms in India. By the early 1990s, most utilities in the US had implemented some form of IRP. Even after restructuring of the US electricity sector in the 1990s and the introduction of electricity markets, the use of IRP continued. There were differences in the way IRP was implemented by different regions, states and municipalities in the US. Further changes were made in the electricity industry leading up to the present, driven by reduction of renewable energy costs, climate concerns, demand reduction, increased consumer choice and greater deployment of information and communication technologies. However, despite the changing times, IRP continues to be considered important.

Many developing countries have also adapted IRP into their electricity sector planning. In India, Professor Amulya Kumar N Reddy had pioneered the use of IRP when he prepared an alternate electricity plan for Karnataka in 1990. This plan could provide the same energy service as the Karnataka government’s plan in less than half the cost. This method was adapted for Maharashtra by Prayas in 1994, and the IRP needed only 60% of the cost of the Maharashtra government’s plan.

IRP is a long term plan with a time horizon of 10-20 years. Figure 8.2 gives a schematic of the IRP process for a state (or a distribution company) and the following paragraphs briefly describe its constituent steps.

Figure 8.2: Schematic of IRP process for a state or distribution company

Source: Adapted by the authors from Figure 1 of the report ‘Future of electricity resource planning’, published by Lawrence Berkeley National Laboratory (2016), and Figure 2.1 of the report ‘Fixated on Megawatts’, published by the Centre for Energy, Environment and Resources (2018)

Demand Forecast

The first step is to estimate the electricity demand required to cater to all consumers. A development oriented, end- use driven, bottom-up approach is the best method to meet this objective. It is recognised that what consumers need are energy services like light, weather conditioning and hot water, and not electricity supply per se. Constructing airy rooms or using solar water heaters reduce the need for electricity, but provide the same service. The end-use estimation is not based only on historical trends, but also development priorities. If rural electrification or promoting small scale industry are priorities, demand is modified accordingly.

The output of this exercise is the electricity demand requirement for the whole state for the next 10 years. This will need energy requirements (MU) and power (MW) requirement patterns (load curves for different typical days).

Electricity supply options

Different supply options are put in place to meet the demand. These options primarily provide centralised and distributed generation options (conventional and renewable), and the costs involved to operate them. Based on the supply options, it is possible to arrive at the fossil fuel requirements, transmission system plan and support services plan. The fuel requirement covers fuel sources, transport options and costs. The transmission system can help to reduce local generation requirements since it may be economical to transmit power from far rather than transport fuel and help to share generation resources across states.⁴ Transmission grid helps to optimise generation resources, since fuel availability and demand patterns in different areas are not same. It also helps to improve the reliability of the overall system, since generation from other states can easily be made available in the case of failures. Ancillary services include peak power, reactive power, emergency generation reserve, etc. These are needed to increase the reliability of the system.

Impacts of end use efficiency by way of energy conservation (avoiding wastage), use of efficient appliances and demand side management are used to reduce electricity supply needs and costs. As seen in Chapter 6, energy efficiency (also called nega-watts) may be much cheaper than generation. Demand side management and demand response help to make the load curve suit the generation pattern of the utility so that the existing generation capacity is optimally utilised. Cost-effectiveness of end use efficiency will depend on the supply option. This approach of treating energy efficiency as a competing supply option, rather than a demand modifying input, has many advantages.

The output of this exercise will be options for a mix of generating stations and the transmission system capable of meeting the demand of the next 10 years and also handling any failures. The generation mix will have conventional and renewable stations, centralised and distributed in location, capable of meeting base, peak or intermediate loads. For each option, the cost involved will also be given. Since the state will have some existing generation and transmission capacity, these options will suggest adding a few more and perhaps retiring others.

Uncertainties and risks analysis

It is not possible to predict the future and certainly not the future of the electricity sector with 100% certainty, since changes in many factors cannot be anticipated, especially over a longer time frame. Uncertainties and risks could be organised into three types: a) planned or for which one can be prepared, b) unplanned, but which can be approximately quantified and c) unplanned and which cannot be quantified.

These different types of uncertainties and risks are handled in different ways:

Planned: Uncertainties that can be anticipated and thus prepared for include demand changes, periodic maintenance, changes in fuel supply quantity or cost (coal, gas or water in a reservoir), short circuits due to lightning, and effects of sudden failures of a transmission line or generator. Periodic maintenance can be staggered so that required generation is available through the year. The protection system protects a transmission line when a short circuit occurs, but that transmission line may go out of service.

Unplanned, but can be approximately quantified: These include variations in usual trends in demand, technology or cost, unforeseen outage of a generator or a transmission line, and weather changes leading to changes in wind or solar generation. There could also be changes in environmental regulations, or shortage of water impacting coal based generation. Assumptions about the cost of generation or energy efficiency could change with technology innovations. There are many uncertainties in the pricing of fossil fuels, which will change the cost of generation. These can be approximately quantified using past behaviour and statistical models. With improvements in weather monitoring and modelling, forecast of wind and solar generation is improving. Power system planners may be aware of this aspect, but the extent of application depends on the sophistication of the planning process.

Unplanned and not easy to quantify: These include natural disasters, major accidents, strikes by employees, riots or technology breakthroughs. It is not possible to exactly predict the timing or impact of such events, and there are limits to the preparedness that can be planned. Only those ready to invest a lot for reliable power supply can construct rugged systems with multiple backups.

Planning for backups and reserves is part of the planning process, so that such uncertainties do not result in a failure of supply. This is reasonably well understood in power system planning. The amount of backup or reserve depends on the expected levels of reliability, which in turn is a policy decision. Developed countries like Singapore or the US plan for significant backups so that failure is rare. In India, Mumbai’s distribution system is robust and well maintained due to high investment, which explains the rarity of power failures in Mumbai. Mumbai also has the highest electricity tariffs, which indicates that it is costly to replicate this across the country. Urban and big consumers expect reliable supply, whereas occasional failures may be tolerable for small consumers, especially if such events are predictable. Since big consumers have the option of purchasing power from the market, they may reduce risks by purchasing power from generating stations outside the state. With falling price of solar PV, they can also opt for captive generation to meet their power needs.

After an informed study of possible uncertainties and risks, different scenarios can be prepared based on an analysis of the impact of these uncertainties and risks on the plan.

Selecting an option

From the different supply options given in the previous step, several options for transmission, distribution and demand are developed. Based on modelling tools for capacity expansion and load dispatch, the best option is chosen. The objective is to minimise the cost over the planning period while meeting the demand.

Preparing an action plan

Based on the selected option, an action plan is prepared to schedule setting up new generating stations and retiring others. Plans for setting up the required transmission and support systems are also prepared. Accordingly, distribution infrastructure plans are also made.

Monitoring and evaluation

In addition to the monitoring of the implementation of plans by the respective generation and transmission companies, the state transmission utility (the state owned transmission company) and the regulatory commission are expected to monitor progress periodically. Inputs from this process help to make mid-course corrections and improve future planning processes.

Regulatory and policy oversight

Preparing an IRP needs a sectoral vision based on development objectives. The state government, state transmission utility and state electricity regulatory commission are expected to provide required policy and regulatory guidelines and oversee the planning process at all stages. For example, planning to increase the annual per capita consumption of India (1150 units/year in 2018) to match that of the world (around 3 times India’s per-capita consumption), China (around 4 times) or developed countries (6-10 times) will require a large extent of resources and cause ecological harm, if the supply increase is mostly driven by conventional options.

But it is important to have moderate increase the energy supply, especially with renewable options, and ensure more equitable distribution of electricity to reduce poverty and impoverishment. Public consultations and contributions from all sections of society will help to arrive at a balanced policy approach that is suitable for the country and the state.

8.3. How does planning happen in India?

Long term planning in the electricity sector has been a function of the central government. The Electric Power Surveys (EPS) of the CEA, 5-year plans of the Planning Commission, the National Electricity Plan prepared by the CEA under the E Act, and occasional national planning efforts like the Integrated Energy Policy (2006) are examples of such long term planning. In addition to these, there are area specific plans like the 175 GW renewable energy target by 2022, energy efficiency targets under the National Mission for Enhanced Energy Efficiency, rural electrification plans under the Deen Dayal Upadhyaya Gram Jyoti Yojana (DDUGJY), and the urban distribution system improvement plan under the Integrated Power Development Scheme (IPDS). States use these plans as inputs into their planning process. Distribution Companies (DISCOMs) are expected to prepare medium term load forecasts and resource plans periodically. This happens under the Multi Year Tariff (MYT) framework, where each DISCOM is expected to project demand growth, generation requirements, investment needs and tariff plans for next 3-5 years. This was briefly covered in Chapter 7. Year ahead plans are prepared by utilities as part of the annual tariff revision process, as described in Chapter 7. Short term operational plans are prepared by utilities to guide their day-to day-operation.

In this chapter, we explore the important long term central plans like the Electric Power Survey (EPS) and the National Electricity Plan (NEP), as well as state level medium term planning exercises.

8.3.1 How does the CEA prepare demand forecast?

The Central Electricity Authority (CEA) prepares a national Electric Power Survey (EPS), once in 5 years, giving long term demand forecast for the next 5 years and a perspective plan for a longer period. The 19th EPS was prepared in 2017, has long term demand forecast till 2022, and perspective plans for 2027 and 2032, for the country and all DISCOMs and states. After the E Act, the CEA also periodically prepares the National Electricity Plan with a five-year plan and 15-year perspective plan. The recent plan for generation was released in early 2018 and a draft transmission plan was released in end 2016. These plans use data from the EPS prepared by the CEA.

The Electric Power Survey (EPS) prepares forecast for the electrical energy and peak demand requirement over the years. This forms the basis for planning the generation, transmission and distribution all over the country. Chapter 1 of the EPS describes the methodology used by the CEA for demand forecast. Consumers are divided into eight categories:

Domestic

Commercial

Public lighting

Public water works

Irrigation (agriculture pumps and lift irrigation)

Industry (LT, HT with less than 1 MW connected load, and HT with more than 1 MW connected load)

Railway traction

Bulk supply to non-industrial consumers (research institutions, government or defence establishments, hospitals, educational institutions, temporary connections, ports, etc)

The EPS uses the ‘partial end use method’ to prepare this forecast. This is a mix of two methods - a) analysis of historical consumption data to forecast future demand, and b) modifying such forecast by using the projected increase in electricity end use. Thus the domestic consumption forecast is calculated using historical data and planned electrification drives, railway traction consumption forecast is modified using track electrification plans, lift irrigation consumption forecast is modified using plans for lift irrigation projects, etc.

Using data given by distribution companies from different states, the CEA first prepares a demand forecast for each of the 8 categories of consumers supplied by a DISCOM. Based on the historical data of energy consumption by a category, the annual specific energy consumption is calculated. This would be the annual energy consumption by a household, energy consumed per horse power of an irrigation pump set, energy consumed to produce a tonne of cement, etc. These figures are modified using factors like expected higher penetration of appliances, improvement in efficiency and reduction of power cuts. Inputs given by the DISCOMs - like Make in India, introduction of electric vehicles and solar roof top systems, are also taken into account. Based on historical trends and policies, the consumer growth figure for future years is calculated. This would be the number of domestic connections, irrigation pump set connections, railway track kilometres electrified, tonnes of cement produced, etc. Using the specific consumption and the growth rates, the yearly energy requirement for each consumer category is calculated for the next 10 years. The total of these annual figures in each category gives the annual energy requirement for the DISCOM at the consumer end in Million Units (MU).

The energy requirement at the consumer end has to be converted into the energy generation requirement. This is done by adding the Transmission & Distribution (T&D) losses in the DISCOM area (intra DISCOM). The T&D loss figures given by the DISCOMs as per the agreed loss reduction trajectory are used. The T&D loss is added to the consumer energy requirement to get the energy generation requirement of the DISCOM. The energy generation requirement of the state is calculated by adding the energy generation requirement of all DISCOMs in the state and accounting for the inter-DISCOM T&D losses.

The annual peak generation requirement (also called peak load, in MW) is an important parameter to be calculated. We have seen in Chapter 3 that the Load Factor is the ratio between average load and peak load. The load factor depends on the pattern of load in a state. If there are many loads which operate round the clock, round the year (like some factories), the load factor will be close to 1. If most of the load is domestic which uses electricity during a few hours of the evening and night, the load factor will be low. The load factor will also depend on the extent of load shedding. Based on the analysis of past load factor values and the expected future load mix, the load factor for each DISCOM is worked out. Using the appropriate load factor, the peak demand for each DISCOM is calculated.

The load factor varies across states between 50% to 80%. The CEA has assumed a load factor of around 80% for the demand projections, with a slow reduction to around 78% over the years. Using the load factor and the annual energy requirement, the peak load forecast for the DISCOM is prepared. Since there are many DISCOMs in a state, the peak load of a state may not be the sum of peak demands of all DISCOMs, since all peak demands may not happen at the same time. To get the peak load of the state, the Diversity Factor (DF) for the state is used. We have seen in Chapter 3 that the diversity factor is the ratio of the sum of individual maximum demands to the system maximum demand. In this case, the DF will be the ratio of the sum of DISCOM peak demands to the state peak demand. The historical values of DF are analysed to calculate the DF for the forecast period.

A similar exercise is carried out for all states in a region. Forecast values of the constituent states are used to arrive at the forecast for a region (e.g. the Southern Region consists of the states of Andhra Pradesh, Karnataka, Kerala, Puduchery, Tamil Nadu and Telangana). The energy requirement figures of the states are added up to get the total energy requirement of the region. To get the peak demand, the Diversity Factor of the region is used. The regional DF values for the forecast period varies between 1.07 and 1.125. Based on the peak forecast for the states and the assessed value of DF, the peak generation requirement for the region is calculated. The same method is extended (by using the forecast of all five regions) to calculate the all-India forecast of energy and peak demand. The all India diversity factor used for the forecast period is 1.065.

The EPS prepared by the CEA is used in most other plans prepared at the national and state levels. But the EPS has some limitations. The CEA is not able to independently verify the input data provided by DISCOMs and other agencies. The demand data is not based on load surveys to identify appliance usage patterns, and the differentiation of demand in the essential, desirable and luxury categories. Savings due to energy efficiency are often based on normative figures⁵. With all these shortcomings, the data could have many gaps, and independent verification of sample data will improve the quality. Big consumers now have the option of getting their power supply from the market or through captive power. Though this will reduce the DISCOM demand, this aspect is not factored into the planning process. The CEA forecast is for the energy and peak load requirements. Generation planning requires that the capacity needed meet base and peak loads, but this information is not available in the plan. Using peak demand to plan generation capacity can result in excess base load capacity, leading to surplus. An analysis of the CEA’s plan indicates that demand projections have been very high compared to actual trends. Figure 8.3 is a study of five EPSs of the CEA. It can be seen that the CEA has been overoptimistic in projecting demand growth.

Figure 8.3: Comparing CEA demand projections and actual demand growth

Source: Compiled by the authors from Electric Power Survey reports of CEA

The erstwhile power shortage syndrome could be one of the reasons for these overoptimistic demand forecasts. But now the situation is slowly changing. In all the five-year plans up until the 12th plan (2012-2017), the actual generation capacity added was less than what was planned. It was around 50% in the 8th, 9th and 10th plans; and 70% in the 11th plan (2007-12). In the 12th plan, as against 88,537 MW capacity that was planned to be added, 99,210 MW was added, and 56% of this was by private companies. This has been one of the reasons for power surpluses with many generating stations not being able to sell their power.

8.3.2 Other national level planning exercises

Other national planning exercises include the National Electricity Plan, five-year plans, and the Integrated Energy Policy (2006) prepared by the Planning Commission. There are also some international reports such as the India Energy Outlook 2015 prepared by the International Energy Agency.

National plans and programmes in specific areas include the renewable energy plan to achieve 175 GW renewable capacity by 2022, rural electrification programmes, urban distribution system improvement programmes, the ‘Power for All’ programmes jointly prepared by the states and the central government (signed by different states in the 2014-2017 period, aiming to provide 24 x 7 supply to all by 2022), and efficiency programmes in lighting, industry, buildings, etc. The NITI Aayog had started preparing a National Energy Policy with a draft in 2017 to lay out an energy policy road map till 2040. But this draft has not been finalised as of end 2018.⁶ Many of these exercises use CEA plans as inputs.

As per the E Act, setting up a generating station does not require a license. Private companies can own and operate transmission and distribution systems after obtaining a license from regulatory commissions. Even in this situation, national plans provide signals to investors in generation, transmission and distribution. For example, according to the draft National Electricity Plan on generation released in end 2016, considering that 50,025 MW coal power capacity is under construction, there is no need to plan any new coal power plants in the period 2017-22. This was a clear signal against coal based capacity addition. The plan was revised in 2018 when it was finalised, which stated that 47,855 MW coal power capacity is under construction and 6455 MW coal power needs to be added in the period 2017-22 to meet peak demand and energy needs.

National Electricity Plan

As per the E Act, the CEA is to prepare the National Electricity Plan with a short term framework of five years as well as a longer 15-year perspective. This plan is to cover the following:

Short term and long term demand forecasts for different regions

Locations for capacity additions to generation and transmission based on economics, reliability and environmental considerations

Fuel choices based on economy, energy security and environmental considerations

The first National Electricity Plan was prepared in 2007, the second in 2013 and the third in 2018, with 2016-17 as the base year. Volume 1 of the 2018 plan discusses the generation plan (with separate coverage of coal, renewable, hydro, gas and nuclear), while Volume 2 discusses the transmission plan. Inputs are invited from different sectors and the public on the draft plan put up on the CEA website.

This plan has a review of the achievements compared to the previous plan, demand projections, generation planning, fuel planning, fund requirement, research and development and human resource requirements. The CEA’s EPS is used for demand projection. An Electric Generation Expansion Analysis System model is used for generation planning. Appropriate reliability indices like spinning reserve (spare generation capacity available from generation units that are operational - specified as 5% of the total capacity by the National Electricity Policy 2005), Loss of Load Probability (LOLP is the probability that the load will exceed the available generation), and Energy Not Served (Energy Not Served or Supplied - ENS is the short supply of energy measured in MU/year or as the percentage of energy shortage) are used. In the NEP, the CEA uses LOLP of 0.2% (for comparison, China’s is 0.14% and that of the US is 0.03%) and ENS of 0.05%.

Transmission planning

Planning for the transmission system is done by multiple agencies. Volume 2 of the National Electricity Plan which is being prepared by the CEA is on the transmission system. As of 2018 the draft is available, for the plan from 2017 to 2022 and the perspective plan till 2036. It uses demand and generation projections as per Volume 1, considers expected technological developments, different energy supply scenarios and cross border transmission links. This plan covers all inter-state transmission systems up to 132 kV level and intra-state transmission systems up to 66 kV level. Transmission companies like POWERGRID, state transmission companies and private transmission companies prepare their own plans. Special plans in transmission include green corridor transmission systems to evacuate renewable power, strengthening the interconnections between regions towards fully operationalising one nation-one grid, and transmission lines to neighbouring countries for export/import and constructing a SAARC grid.

Transmission planning is carried out as per the planning criteria manual issued by the CEA in 2013.⁷ The transmission system consists of Inter-State Transmission System (ISTS) connecting multiple states, and the Intra-State Transmission System (Intra-STS) limited to the state boundary. The CEA prepares the framework and first level plans for the country. The Central Transmission Utility (POWERGRID in this case) is responsible for national transmission planning up to 132 kV level, and the state transmission utility (the state owned transmission company) is responsible for state level transmission planning up to 66 kV level.

The CEA prepares the manual on transmission planning criteria, the current version of which was prepared in 2013. The first version prepared in 1985 and the second version prepared in 1994 focussed on regional self-sufficiency. With the interconnection of all regional grids and many technological developments, the 2013 version focusses on bulk interregional power transfer to form a stable national power grid. The grid failure in July 2012 has increased the importance of increasing grid reliability to withstand unforeseen events.

Transmission planning is typically carried out for a 3-5 year time horizon. The demand forecast prepared in the EPS is used at a broad level, and transmission companies provide substation-wise demand data. In addition to active power (MW) forecast, reactive power (MVAR) forecast is also important in transmission planning.

Transmission planning is an exercise to arrive at a suitable balance between the costs and the risks involved. Questions to be addressed include the following: What types of contingencies (another word for unforeseen events) should be considered? How much redundancy should be planned? How can critical loads like railways face minimum power failure? It is not possible to go into the details of these aspects here, but we discuss one example related to contingency.

Contingency is an abnormal event in the grid, like a failure of a transmission line or a generator. Contingencies in a grid are described using the notation N-x, where N denotes the number of healthy components in the grid, like transmission lines, transformers and generators, and x is the number of components which have failed. N-0 is a situation where no components have failed. As per the planning criteria, in an N-0 situation, all system parameters (voltage, frequency, and loading of components like lines, transformers and generators) will remain within permissible limits. N-1 is a situation where any one component in the grid has failed. The planning criteria stipulates that even in this case, all system parameters should remain within permissible limits. In an N-1-1 scenario, where one more component has failed, some components may be loaded to their emergency limits, which is a little higher than permissible limits. Load shedding or changing generation levels will have to be carried out to remove the overloads. This has to be carried out within 90 minutes of the event.

The manual provides various parameters like permissible and emergency loading limits, voltage limits (typically 5-10%), maximum phase angle separation between two adjacent substations (30 degrees), time limit for clearing faults (100-160 milliseconds), suggested transformer capacity at substations and criteria to choose HVDC for bulk transmission (more than 2000 MW for more than 700 km). Those interested could read the manual and Volume 2 of the National Electricity Plan.

8.3.3 State level planning exercises

At the state level, planning is carried out as part of the regulatory process. The state transmission utility (typically the state owned transmission company) is required to prepare the intra-state transmission plan, and each DISCOM is required to prepare the power procurement and distribution network plans.

The E Act and Tariff Policy 2006 specify that DISCOMs should carry out Multi-Year Tariff (MYT) planning. The planning horizon (also called control period in this context) suggested is 3-5 years. Most states have regulations on the procedures to prepare and review MYT plans. A typical MYT process starts with a business plan prepared by the DISCOM for the control period. This will have consumer category-wise sales and demand projections, a power procurement plan, capital investment plan, financing plan and performance targets. Once this plan is approved, the DISCOM is expected to submit annual expenses and a revenue plan. Factors which are controllable (which can be managed by the DISCOM) and uncontrollable (disaster, change in law, change in taxes, etc) will be identified in the plan. The gain or loss due to changes in uncontrollable factors will be passed on to the consumer. The gain or loss due to controllable factors will be shared between the consumer and the DISCOM. The MYT plan is to be reviewed on a periodic basis. Comments from the public are invited during the preparation of the MYT plan and public hearings held.

In the 2014-2017 period, most states prepared Power for All (PFA) plans with support from the Ministry of Power. These plans aim to provide 24 x 7 power to all consumers (by 2019 or 2022, depending on the state), except agriculture, which is assured of 8-10 hours supply. These plans cover all aspects of the state electricity sector: demand estimation, generation, renewable energy, transmission, distribution and fuel supply. The PFA documents are thus a compilation of all efforts being implemented in the state under different initiatives.

The MYT and PFA processes are certainly improvements in the planning process, but their contributions to improving planning depends on whether the DISCOM is rigorous about implementation, on oversight by the state and regulatory commission, and participation by citizens. Capacity addition is the most crucial aspect of planning, since it involves significant investments, and power procurement constitutes 70-80% of the consumer tariff. Many states use the CEA’s EPS figures for their planning, and some states even plan for higher capacity addition without detailed analysis. In some cases, generation capacity addition is planned first and the rest of the plan prepared to handle this. Very few states or DISCOMs have attempted to prepare IRPs. The reason could be the limited incentive that DISCOMs have to reduce their costs, since they are sure of meeting all their costs from the consumer tariff or state subsidy.

8.4. Improving the planning process

As mentioned, planning continues to remain crucial to a healthy electricity sector even after it has undergone fundamental change. Some improvements are possible in the current planning process at the national and state levels.

At the national level, it is important to improve the EPS and National Electricity Plans through better consultations. The CEA puts up drafts for comments and citizens could provide comments and follow up on whether they are incorporated.

At the state and DISCOM levels, Integrated Resource Planning described in Section 2 can form a basis for improving the planning process. Load surveys need to be conducted to understand patterns and trends in electricity use. Actual savings from energy efficiency initiatives need to be assessed based on field studies. Evaluation methods like those described in Chapter 6 should be used to evaluate alternate investment options. It is important to consider the impact on livelihoods and the environment during the planning process. Public consultations have to be held at all stages in the planning process. Lessons from the previous planning reports need to be incorporated. It is also important that planning exercise should include many actors outside the electricity sector, including sectors like coal, gas, railways, industry, irrigation and agriculture. It is important to adopt a comprehensive approach based on inputs from these sectors.

Demand estimation and generation planning are crucial to planning and deserve special attention. In a shortage scenario, capacity addition in any form is welcomed and there is no need for complex models. As we will see in Chapter 10, the sector is shifting from a centralised supply and grid scenario to a distributed scenario, with many more players. Considering the extent of uncertainties as mentioned in Section 8.2.1, it is important that planning agencies use modelling tools to draw up plans for different scenarios.

Endnotes

¹ The economy and electricity consumption have a two-way correlation, rather than a cause and effect relationship. There are direct and indirect impacts of electricity consumption on the economy and quality of life. The multiplier effect is high for electricity dependent activities like industry and agriculture water pumping. With improvements in end use efficiency, it is possible to achieve higher economic gains with less electricity consumption.

² According the Report of the High Level Empowered Committee to Address the Issues of Stressed Thermal Power Projects (November 2018), the PLF of gas based plants (67 plants with a total capacity of about 25,000 MW) in 2017-18 was 22%, due to the low availability of gas. The report also gives details of 34 stressed thermal projects with 40,130 MW capacity. The full report is available at https://powermin.gov.in/sites/default/files/webform/notices/20_Nov_R1_Draft_Report_HLEC_Final_20_Nov.pdf

³ For example, the 2006 Integrated Energy Policy assumed 8% or 9% GDP growth and electricity elasticity (ratio of per-capita electricity generation to per-capita GDP) of 0.95 to 0.78 to forecast electricity supply needs from 2005 to 2032.

⁴ The transportation cost of coal can be quite high if the power plant is located far from the coal mine. As of 2016, the transportation cost is around 10 paise/Unit for 100 km and around 2 Rs/Unit for 2000 km. The average distance between mines and power plants is around 500 km. Some reports indicate that for distances over 300 km, transmitting electricity over HVDC lines is more economical than transporting coal. See the report ‘Indian Railways and Coal’ by Brookings India (2018), especially Appendix 1 and 2.

⁵ Normative figures in this context refer to expected electricity savings due to efficiency measures. For example, replacement of an agriculture pump set with an efficient pump set is expected to save 30% energy.

⁶ The draft is available at http://indiaenergy.gov.in/national-energy-policy/.

⁷ The CEA’s Transmission Planning Criteria Manual is available at http://cea.nic.in/reports/others/ps/pspa2/tr_plg_criteria_manual_jan13.pdf

9 : A quick tour of electricity sector reforms

In this chapter, we look at the ‘market oriented reforms’ initiated in the 1990s in the Indian power sector and their stated objectives and impacts. During the first phase of these reforms, private companies entered the field of power generation as Independent Power Producers (IPPs). This was followed by a second phase, called the Odisha model after the state where it began, during which the generation, transmission and distribution functions of State Electricity Boards (SEBs) were ‘unbundled’ and handed over to state owned corporations. Regulatory Commissions were set up as regulators of the sector, with the state limiting its role to providing policy guidelines. In some states, distribution utilities were privatised. The third and ongoing phase of change in the sector, which aims at furthering competition, began with the enactment of the comprehensive Electricity Act, 2003. In the context of these reform measures, we briefly discuss key events and controversies such as the IPP policy, privatisation of distribution in Odisha, etc. We also discuss various policy and legal developments and major national schemes and programmes.

This chapter gives a brief overview of the reforms in the electricity sector, which commenced in early 1990s. The first section gives a brief history of the sector from independence to 1990, so as to provide a background to the reform process. First phase of the reform from 1990 to 2003, when the Electricity Act 2003 was notified, is covered in the second section. Third section covers the period from 2003 till now and the fourth section briefly explains the changes in the related coal and fuel sectors. Final section summarises the reform process and introduces the upcoming challenges, which are addressed in Chapter 10. Those interested in a detailed coverage of electricity sector reforms could refer to the Prayas publication, ‘Many Sparks, but Little Light’.¹

9.1 Independence to 1990

We have briefly reviewed the evolution of the electricity sector in Chapter 5 (refer to section 5.1). As explained earlier, at the time of independence, the Indian electricity sector was largely controlled by private companies, and electrification was limited to big cities and industrial centres. The State Electricity Boards (SEBs) were formed in the 1950s under the Electricity Supply Act 1948 to extend supply beyond cities. Figure 9.1 shows a simple schematic representation of a vertically integrated state level power sector. Generation, transmission and distribution along with system operation or load dispatch were handled by only one entity, the SEB, which was owned and controlled by the state government. The SEBs were entitled to charge tariffs that would help them recover the cost and create a modest surplus of 3% over the fixed asset base. However, since the state governments regulated them, they had limited autonomy to set tariffs.

After the formation of SEBs, there was commendable growth in generation capacity, the number of electricity consumers and agricultural pumps, and the length of the electricity network. There was also significant improvement in technological capabilities, and development of skilled, committed personnel in the sector. This impressive growth was the result of four broad policies. The first was government ownership and support from central and state budgets. The second was the development of a centralised electricity supply system and of regional and national electricity grids. The third major policy was the thrust on self-reliance in technology and fuels. Under this policy, autonomous but government-owned companies like Bharat Heavy Electricals Limited (BHEL) were created to develop technological capabilities. Similarly, emphasis was laid on utilisation of the available energy sources such as coal and hydropower. Finally, the policy of cross-subsidy, i.e. rich consumers subsidising the poor, was adopted widely, which reduced the tariff for small homes and agricultural users.

Figure 9.1: Schematic representation of a vertically integrated utility

Source: Prayas (Energy Group)

In addition to the SEBs, the central government played a significant role in the electricity sector. The Ministry of Power (MoP)² was responsible for the legal and policy formulation for conventional electricity, and the Ministry for New and Renewable Energy (MNRE)³ for the promotion of renewable energy. The Central Electricity Authority (CEA), set up in 1951, was responsible for national level planning, regulation and data collection. With a view to speed up generation capacity addition, the central government set up the National Thermal and Hydro Power Corporations (NTPC and NHPC) in 1975. It also set up a national transmission company, POWERGRID, to construct and operate inter-state transmission to transport the power generated across the country.

However, towards the late 1980s, the financial health of SEBs started deteriorating rapidly, and as the demand for electricity started growing, the generation capacity was not able to keep pace with it. As a result, power shortage became a common phenomenon. Financial problems worsened the ability of SEBs to add generation capacity or expand the electricity network and thus, electrification of villages and rural households also suffered.

9.2 First phase of the market oriented reforms: 1990 to 2003

The deterioration in SEB performance, mentioned in the previous section, can be traced to failures on four fronts: techno-economic (high technical losses, low efficiency, poor project implementation); policy (poor targeting of subsidy, reducing support to the public sector); planning (overemphasis on centralised supply approach, neglect of end-use efficiency), and governance (undue interference in SEB functioning by the state government, corruption, project delays, bad management). There were many attempts to study these failures by government committees and funding institutions like the World Bank. Electricity sector reforms, which started in early 1990s identified the inability of state utilities to raise finances as the main problem, and privatisation was suggested as the solution to address all ills of the sector. This was in accordance with the broader economic framework of Liberalisation Privatisation and Globalisation (LPG) being adopted in the country. This was also in line with other energy sector policies during this period, such as the efforts to encourage private participation in the coal sector by allocating captive coal blocks, and auctioning in oil and gas exploration and production segments.

At the core of this reform was a policy shift that saw electricity as a tradable commodity, unlike its traditional role as a development input. Increase in private sector participation, greater role of market forces and thus, a reduced role of the state, were key to this reform process.

World over, through the late 1980s and the early 1990s, many countries undertook a fundamental restructuring of the electricity sector to ‘unbundle’ the vertically integrated utilities. Generation was considered to be more amenable to competition, while distribution and transmission were allowed to be ‘natural monopolies’, meaning that it was better to have only one operator for these services in an area. It must be noted that at this time there was no concrete evidence of efficiency gains due to increased competition in generation.

In India, private companies were given entry into generation sector in early 1990s. Odisha was the first state to adopt the model of unbundling and privatisation, starting from 1996. Electricity being a concurrent subject, Electricity Reform Acts on the lines of the above philosophy were passed by some states.⁴ In 1998, the Electricity Regulatory Commissions Act was passed by Parliament. It empowered state governments to create their Electricity Regulatory Commissions, removing the need for individual state legislations. Several states such as Maharashtra, Tamil Nadu and Punjab established regulatory commissions under the 1998 Act, though these states did not immediately take up unbundling and privatisation.

The Central Electricity Regulatory Commission (CERC) was established in 1998, and by 2000, it had notified a grid code, issued terms and conditions for tariff for the NTPC as well as other central sector power stations, and was adjudicating on disputes between the private generators (called Independent Power Producers (IPPs) and SEBs. The financial position of the SEBs weakened further and the extent of the problem became more evident because of the transparency brought in by the ERCs. For example, in 2001, the Maharashtra Electricity Regulatory Commission (MERC) re-estimated the agricultural consumption in Maharashtra and declared that the MSEB’s T&D losses were a staggering 39%, and not 18% as claimed by it. The tariff processes conducted by the ERCs provided opportunities to scrutinise the cost and revenue of the SEBs, and to debate the appropriateness and extent of cross-subsidies. Thus, the ERCs began ‘rationalising’ the tariff structure of the SEBs, as a result of which tariffs of the subsidised segments of the SEB consumer base, including agricultural and domestic consumers, started increasing.

These developments led to a great deal of churning and change in the sector. The CERC helped review the performance of the central sector power stations, when the issue of non-payment of dues for power purchase costs by many SEBs came into focus. With greater transparency regarding the costs and revenues of the SEBs, the state governments came under pressure to own up the losses and finance the subsidies that they had announced. One of the fallouts of these changes was that the central government began to exert a greater say in the functioning of the sector.

In 2001, the central government set up the Ahluwalia committee to decide the mechanism for the settlement of SEB dues. The committee placed a great emphasis on operating SEBs on commercial terms and improving their efficiency by reducing Aggregate Technical and Commercial (AT&C) losses. A number of schemes involving deductions from the centre’s plan assistance were initiated by the central government to repay the accumulated dues of the SEBs from time to time. Under the 2001 scheme, 50% of the interest payable by the SEBs to various public sector undertakings in the power sector was waived, and the remaining amounts were converted into long-term loans to be repaid by the state governments over 15 years. The terms and conditions proposed in the 2001 bailout scheme were subsequently converted into a binding law under the Electricity Act, 2003.

The following sections discuss the major steps during the first phase of reforms.

9.2.1 Opening up of electricity generation

In 1991-92, the country launched its power sector reforms by opening its generation sector to private and global investors with a package of policy measures, which was expected to attract profitable investment opportunities. For this purpose, the government amended laws and regulations, and offered a set of incentives to make investments lucrative. Later on this policy came to be known as the Independent Power Producers (IPP) Policy.

The basic rationale for this move was that the government did not have the resources for the development of the electricity sector, which necessitated the involvement of private players. As the main objective was to bring in additional resources for the capacity addition programme in the electricity sector, a few conditions to ensure private investment were introduced. While the IPP policy mentioned the need for faster clearances and speedy processes for fuel linkages, issues such as rigorous demand estimation, least cost options for meeting the demand, feasibility of coal production to meet the new generation capacity, its transportation, and other such constraints were not deliberated upon.

In response to this policy, around 243 Memoranda of Understanding (MoUs) for over 90,000 MW of capacity - 16 times more than the stated shortfall of around 5,500 MW, and also more than the country’s total installed capacity at the time - were signed.⁵ However, despite this frenzied response, the projects were not selected through an open and transparent bidding process, and the terms and conditions of the MoUs and the power purchase agreements (PPA) were strictly guarded as ‘confidential’ documents which were not accessible to the public. Many of these projects were based on imported fuel and technology, and were linked to foreign currency rate variations. This raised serious issues concerning energy security and made the economics of these projects unviable. Such factors along with the lack of transparency in negotiating the PPAs increased the uncertainty regarding pricing of this power and increased the overall costs that consumers had to bear. Box 1 presents a brief overview of one of the most controversial projects of the IPP era, the Dabhol power project, promoted by the Enron Corporation.

With its numerous twists and turns, the Enron saga demonstrates the many flaws of the IPP policy and offers important lessons. One of the most important learnings that emerged from the IPP policy failure was the need to introduce bidding as a method of selecting a project. While next steps in reforms factored in this issue, not much attention was paid to the other crucial failures, such as absence of a rigorous demand estimation process, power purchase planning and level playing field for competition. These are related to governance issues like lack of transparency, weak regulatory oversight and poor coordination with interlinked fuel and finance sectors. There continued to be a disproportionate focus on attracting private investment.

Though the IPP policy aimed at encouraging generation capacity addition of all kinds, including large hydropower and renewable energy sources, the most enthusiastic response was from the thermal, i.e. gas and coal generation segments. In spite of coal being more readily and cheaply available, most of the projects for which MoUs were signed during the 1990s were based on gas and that too, imported gas as the primary fuel. Naturally, the electricity from these projects would have been quite expensive. However, most of them never materialised and the few that did were stranded for want of fuel or buyers for such expensive power.

Private sector interest in large hydropower projects has been lukewarm, though many schemes and policies have been introduced to attract private investment for these projects. One of the most challenging aspects of hydropower development has been the uncertainty regarding the ‘final’ cost and actual generation. Interestingly, in the early years of the reforms, the government appointed Sambamurti committee acknowledged that the main difficulty in privatising hydropower generation was determining the real cost of such projects so as to ensure that the major risks of the private operator were covered, without allowing them to claim excessive and underserving costs.⁶ This raised the question of whether hydropower generation could at all be opened up to the private sector, particularly under the cost-plus tariff dispensation. The lack of success notwithstanding, the reforms continued to push for privatisation in hydropower.

Since 1991-92, about 24,000 MW of hydropower capacity has been added in the country, but only 3004 MW of this (~12%) was added in the private sector. In fact, even in the years following the first phase of the reforms, the response of the private sector to hydropower remained poor, and till date, private hydropower projects constitute a minor part (around 7% in 2018) of the entire installed hydropower capacity in the country.

Turning to renewable energy (RE) development, in 1992, the newly formed Ministry of Non-conventional energy sources (MNES) issued a policy advisory to the states to price renewable electricity at a minimum of Rs 2.25/kWh (with 1994-95 as the base year) with an annual escalation of 5% for the 10 years during which the sector began its first phase of growth. This price certainty along with benefits such as accelerated depreciation, 100% foreign direct investments (FDI), energy banking and concessional third party sales resulted in a significant growth in the wind, biomass and small hydropower generation capacity. Nearly all of the 3400 MW of RE capacity installed by 2002 was set up with private investments and negligible state ownership, in contrast to the thermal, hydropower, and nuclear sectors.

Box 9.1: The Enron story

The MoU between the US based Enron Development Corporation and the Maharashtra government for the Dabhol Power Project was signed in 1992. Enron planned to build a combined cycle gas technology based thermal generation plant with an installed capacity of 2015 MW in two phases. The initial MoU was only signed for the first phase of the Enron project (695 MW), and the Maharashtra government was not bound to sign an MoU for the remaining capacity. Considering Maharashtra’s demand and supply situation at the time, serious questions were raised by civil society as well as opposition parties in the state about the need for such capacity addition and the choice of technology, fuel availability and affordability.

The project became a major political controversy during the 1994 state assembly elections due to several questionable aspects including the fact that the MoU was kept under wraps. Though the opposition had campaigned against the project and promised to review it as an election plank, when it came to power, the new coalition government reneged on its promises. After a series of convoluted twists and turns, the government backtracked on its initial decision to scrap the project. Instead, it renegotiated the tariff and signed a contract with Enron in 1996 for both phases for the entire capacity of 2015 MW.

In 1999, when only one unit of the plant started running, the cost of generation shot to Rs 7.5/unit. The cost was unacceptably high for two main reasons: a) the dollar linked high cost of the imported fuel, and b) the capacity was contracted as a base load plant and hence, even in the absence of demand, the full capacity charge had to be paid. The contract was heavily in Enron’s favour and it was estimated that the company would earn a rate of return to the tune of 21-30%, which was almost double the usual rate of return for such projects.

If the project had to make economic sense for the Maharashtra State Electricity Board (MSEB), the average consumer tariff would have had to increase at more than 15.5% per annum for the next two decades. In spite of such preposterous economics, the state government gave sovereign guarantees if the MSEB were to default on payments. By the year 2000, it became clear that even if only Phase I was allowed to continue, it would lead to the financial collapse of not just the MSEB, but potentially of the state government.⁷

There was more to the Enron controversy than bad economics. The plant also failed to meet its technical commitments and in spite of being a gas based project, it could not vary its generation in accordance with load dispatch instructions. This technical and operational glitch enabled the MSEB to rescind the contract in 2001. During this time, the Enron Corporation also found itself engulfed in a major financial scandal and filed for bankruptcy in the US. In spite of repeated suggestions, the government failed to buy Enron’s equity in the Dabhol Power Corporation. Had this been done, a lot of further litigation and resulting costs could have been avoided.

Subsequently, the project was revived as the Ratnagiri Gas and Power Pvt Ltd (RGPPL) project in July 2005. The cost of reviving the project was estimated to be between Rs 6,000 to 8,000 crores, which was entirely borne by the Indian taxpayer. The project now became a joint venture of NTPC, GAIL (India) Ltd, and the MSEB Holding Company along with some public financial institutions. After revival, commercial operation of Block II and Block III, each of 663.5 MW, was declared in 2007. Block I of the generating station of 640 MW was commissioned only in May 2009 after significant repair.

Since 2007, the project has consistently failed to perform either on account of technical and operational problems or due to a lack of fuel. Hence, treating it as an in-firm source, the Maharashtra state distribution company (MSEDCL) refused to pay the capacity charges. This decision of the MSEDCL has been challenged by the RGPPL. The Gas Supply Agreement between RGPPL and Reliance’s Krishna Godavari Dhirubhai 6 (KG-D6) expired in March 2014, and since then the plant has no firm gas allocation. On these grounds, the MSEDCL has (yet again!) terminated its contract with RGPPL, though the termination has been challenged by RGPPL.

9.2.2 Mega power policy

Not to be discouraged by the early setbacks of the IPP policy and to further boost efforts to add capacity, the central government in November 1995 formulated the ‘mega power policy’ for setting up large scale power plants (1000 MW or more) and supplying power to more than one state. The policy argued that resources such as coal and hydel potential are located in a few areas whereas demand for power could be elsewhere. Hence, setting up large projects at pit heads or best located sites in terms of hydropower potential would help to efficiently use these resources.

Learning from the IPP policy, the government introduced guidelines for competitive bidding in order to select projects. The policy was revised in 1999 to set up the Power Trading Corporation (PTC), with majority equity participation by the Power Grid Corporation of India Ltd (POWERGRID), along with the National Thermal Power Corporation (NTPC), the Power Finance Corporation (PFC) and other financial institutions. Acting as a trader, the PTC was supposed to buy power from these projects and sell it to identified SEBs. Thus, the risk of SEBs defaulting on payments was to be borne by the PTC. The revised policy also introduced new eligibility conditions for the states, which included setting up of regulatory commissions under the 1998 Act, and privatising distribution in cities with a population of more than one million. The policy also provided tax holidays to the identified projects. The import of capital equipment was free of customs duty for these projects. In addition, the promoter could claim a tax holiday period of 10 years in any block of 10 years within the first 15 years of the term of the project.

In spite of the right intentions, the mega power policy could never translate its objectives into the stated benefits. Till date, only about 19 projects in both the public and private sectors could achieve the mega power status. Although this policy was better designed than the IPP policy, it failed to elicit interest from the buyers (SEBs) who were supposed to act on these guidelines. This could be because the states had already signed a large number of MoUs for much larger capacities than that needed for the next 5-10 years. The governance issues regarding the MoU had already been highly politicised, which may have prevented state governments from openly reviewing the capacity addition plans despite the fact that there was considerable doubt regarding the feasibility of most of the MoU projects. Also, the lack of discretionary powers to the states to select the projects under this scheme perhaps dampened their level of interest.

9.2.3 Unbundling and privatisation in Odisha

Odisha was the first state to adopt the new state sector reform model. With the support of the World Bank, the Odisha and Indian governments chose the state to launch reforms in 1996. As part of this process, the direct regulation of the power sector by the state government was replaced by regulation at ‘arm’s length’ by an independent regulatory commission, the Odisha Electricity Regulatory Commission (OERC) that was introduced through the state electricity reforms act. The Odisha State Electricity Board (OSEB) was split into two generation companies for hydro and thermal generation, and the Grid Corporation of Orissa (GRIDCO) set up to manage transmission and distribution. The distribution business was further divided into four distribution companies, and in 1998, international competitive bidding was undertaken for privatising the four companies (offering 51% stake to the private investor, 39% retained with GRIDCO and 10% with the Employees Welfare Trust). In 1999, the Bombay Suburban Electricity Supply (BSES, which was later on acquired by Reliance Energy Ltd)) bid was selected for privatising three of the four distribution companies, and the TEC Consortium for privatising the fourth, namely the Central Electricity Supply Company (CESCO). After the TEC Consortium refused to honour its offer, the AES-Jyoti Structures Consortium (one of the pre-qualified bidders) was offered CESCO after some negotiations. Assets and management control were transferred to the private companies.

After a few years, many problems with the privatisation process began apparent. There was no proper baseline estimation of T&D losses, and the loss reduction targets were unrealistic. No government subsidies were provided to the sector. Demand growth projections turned out to be overambitious. Private companies did not bring in capital or take administrative measures to reduce losses or collect arrears, and dues owed by the companies to the state owned transmission company (GRIDCO) kept increasing. In 2001, the AES abandoned CESCO after not following the contract conditions and the OERC directions, and the state government took over the distribution.⁸ The other three private companies consistently failed to meet the targets for reducing losses and improving supply quality. Rural electrification was neglected during this stage.

The government appointed the Kanungo committee and the World Bank’s implementation commission report candidly noted that the reform had not worked. The Kanungo committee strongly criticised the excessive dependence of the companies on private consultants and the fact that they did not offer sound advice. It recommended that this practice of outsourcing of crucial organisational processes should be ended as soon as possible as it weakens the organisation and demotivates employees. However, the practice has continued ever since and remains quite prevalent amongst both the companies as well as regulatory commissions even today.

The Odisha experiment with privatisation ended in 2015 when the Odisha ERC revoked licenses of the three private DISCOMs controlled by Reliance Energy. The revocation was on grounds of bad performance and for disobeying OERC’s orders on improvement in power supply efficiency. The reasons given were highly unsatisfactory performance (insufficient reduction of losses, non-payment of arrears for power purchase, failure to follow OERC directives, etc.) and non-incorporation of clauses in the shareholder agreement, like transfer of shares to group companies without prior approval (OERC, 2015). The Order notes that the distribution loss has remained at 40% for the past several years (it was around 45% in the first year after privatisation) and the accumulated losses of the three distribution companies were Rs 2424 crores in 2013. Many other states undertook similar reforms, though privatisation of distribution was taken up only in Delhi.

9.2.4 Privatisation in Delhi

Distribution in Delhi was managed by the Delhi Electric Supply Undertaking (DESU) till 1997. The Delhi Vidyut Board (DVB) was set up like a State Electricity Board (SEB) to improve distribution, but with little impact. Being an urban centre, the nature of electricity distribution in Delhi is very different than that in other states. The load density is high and many consumers are better placed financially and can afford to pay for electricity. The DVB was in a very bad shape in 1998, plagued by large technical and financial losses, power shortages, and poor quality of supply. There was all around dissatisfaction about its functioning and there was strong political backing as well as state government support for reforms.

The privatisation effort in Delhi was quite different from that in Odisha. The process was initiated in 1999, when the DVB was split up into seven companies - a holding company, two generation companies, a transmission company and three distribution companies. The Delhi Electricity Regulatory Commission (DERC) was established in 2001 and privatisation began in 2001-02. The privatisation process was handled by the Delhi government with no involvement of the DERC or foreign consultants, as was done in Odisha. Distribution companies in three zones were bid out based on the lowest AT&C loss reduction trajectory (17% reduction in 5 years). The bidders were required to accept regulation of retail and bulk supply costs by the DERC and a 16% return on their capital base, as well as to take over the existing liabilities of the DVB. The Delhi government offered transition support for five years of Rs 3450 crores, in addition to support from central programmes, whereas in Odisha no state support was provided.

After a qualification and bid process as well as negotiations, the Bombay Suburban Electricity Supply (BSES) company won the bids for two companies and Tata Power Ltd for the third. 51% of the shares in the three distribution companies were privatised, with the Delhi government retaining 49%. Compared to Odisha, estimation and reduction targets of losses were better designed in Delhi, and the private companies could meet the targets. Only realisable liabilities were transferred to the new distribution companies, which also benefited from the availability of cheap power from central generating stations.

After privatisation, the AT&C losses have fallen to nearly 14% and the quality of service (in terms of say, transformer failure, complaint handling, or ease of bill payment) has improved considerably. However, doubts have been expressed about the capability of regulatory oversight, especially the correctness of the estimation of AT&C losses and the high level of accumulated financial losses. It is a matter of concern that the distribution companies have resisted being audited by the Comptroller and Auditor General of India (CAG) and do not comply with RTI queries. A clearer picture on the distribution privatisation in Delhi will emerge only if the 2015 CAG audit report is made public, or if the regulatory commission takes proactive measures to analyse the performance of private companies.

9.3 Electricity Act 2003 and beyond

The Electricity Act 2003 (E Act) marked a watershed in the Indian power sector, with fundamental and far-reaching impacts. According to its preamble, the objectives of the Act include promoting competition while protecting interests of consumers and ensuring supply of electricity to all areas, rationalising electricity tariffs, ensuring transparent policies regarding subsidies, and promoting efficient and environmentally benign policies. Some of the more striking features of the E Act include the introduction of open access in transmission and distribution, allowing trading of electricity and delicensing generation (except nuclear and large hydro). The E Act overrides all existing acts governing the power sector, namely the Indian Electricity Act (1910), the Electricity Supply Act (1948), the Electricity Regulatory Commissions Act (1998), and the State Reform Acts. We now discuss the important features of the E Act.

9.3.1 Legal and institutional structure

The E Act mandated the unbundling of vertically integrated SEBs. In the new scheme of things, the state governments were required to divest the SEBs of their powers, and instead form multiple companies, for generation, transmission, distribution as well as a holding company. Apart from unbundling and corporatisation, the Act also mandates the formation of state transmission utilities (STUs), which are responsible for transmission system planning and operation at the state level. Similarly, in order to ensure smooth grid operation, autonomy was granted to the state, regional and national load dispatch centres. In addition to the STUs, the Act also mandates the creation of a central transmission utility for managing the operation and planning of the inter-state transmission system.

The Act placed the ERCs at the centre of the functioning of the sector. Between the Central Electricity Regulatory Commission (CERC) and its state level counterparts (SERCs), these institutions are empowered to regulate most aspects of the sector: they set tariffs for generation, transmission, supply and wheeling; grant licenses for transmission, distribution and electricity trading; and adjudicate on disputes between the various licensees and generation companies. The ERCs also have the power to suo motu, or based on petitions filed before them, initiate proceedings to hold the licensees and institutions accountable for their statutory duties and responsibilities. The ERCs are responsible for a combination of functions including legislative (notifying regulations), executive (implementing rules and regulations) and quasi-judicial functions (adjudicating disputes, compliance with norms and imposing penalties). Checks and balances have been put in place to hold these institutions accountable, including provisions for the tabling of regulations formulated in the legislature, judicial review by constitutional courts, and appeals which can be filed against the decisions of the ERCs. The E Act also set up the Appellate Tribunal for Electricity as a dedicated forum for appeals against the ERC orders.⁹ Prior to the E Act, appeals against ERC orders had to be filed before the respective High Courts.

For the first time in the electricity sector, the E Act introduced a dedicated channel for consumer grievances by mandating the establishment of Consumer Grievance Redressal Forums (CGRFs) by the electricity distribution companies and the post of the electricity ombudsman by the ERCs. The provisions for consumer participation in the regulatory process were also strengthened under the Act, and public participation was mandated at the level of the ERCs in tariff setting, grant of licenses and other important proceedings. Regulatory commissions were mandated to ensure supply and service quality by instituting regulations and norms for voltage, interruptions, network failure, time taken for providing a connection, etc. Failure to meet these norms can entail compensation to be paid by the DISCOMs to consumers for poor service.

National policies and plans on electricity were introduced by the central government. This included the National Electricity Policy, the Tariff Policy, the Rural Electrification Policy and National Electricity Plan. These policies and plans envisaged universal access to electricity, as well as electricity tariffs fixed on commercial principles to encourage competition and efficiency. A massive rural electrification programme with household electrification focus was initiated by the central government in 2005, the implementation of which is in progress since then. The procedure for setting up thermal generation plants and captive plants was simplified, so that such projects did not require prior clearances from the power ministry, but did have to obtain other clearances related to the environment, forests, etc. Measures for competition in generation were introduced. These measures led to a high growth in private generation capacity.

Although relatively young, the ERCs have gone a long way in ensuring public accountability, instilling transparent decision making processes, and encouraging public participation. However, their autonomy has also been severely constrained because the government appoints its Members and Chairpersons and exercises some controls. Government can and do issue policy directions to ERCs on various matters, though ERCs are not strictly bound to follow such advice from the government. ERCs need government approval for creating any new permanent staff positions. Delays in appointments of Members and Chairpersons and inadequacy of capable regulatory staff often limit the effectiveness of these institutions.

In spite of their far and wide powers, unfortunately, most ERCs limit their role largely to tariff determination. Little interest has been shown by ERCs in monitoring supply and service quality or ensuring due compliance by the utilities in this regard. Similarly, although their mandate allows them to do so, most ERCs do no undertake any comprehensive review of implementation of large scale government programmes, such as say the ones aimed at rural electrification or energy efficiency. ERCs are also not accessible to small consumers and seldom take proactive efforts to encourage informed participation.

With all their flaws, the ERCs are still very important institutions and the democratic spaces made available by their presence need to be expanded. With an increasing role of market operations in future reforms, the need for effective regulators will be paramount.

9.3.2 Electricity generation

The Act made generation (excluding that by nuclear and large hydropower) a completely de-licensed activity. Thus, any company with the necessary fuel resources, approvals and clearances (mainly for land acquisition and environmental impacts) could set up a generating plant anywhere in the country. It allowed industries to set up captive plants for their own consumption and also gave big consumers (with load greater than 1 MW) the choice to select their power supplier through the open access mechanism. It laid special emphasis on promoting renewable technology based generation and even mandated the distribution companies, and open access and captive consumers, to meet a certain part of their power purchase requirements from renewable sources.

Under the E Act, distribution companies can undertake competitive bidding to discover the lowest tariff in a transparent bidding process which is defined under the guidelines issued by the central government. DISCOMs can also continue to procure power from state and centre owned plants under a ‘cost-plus’ regime under which the ERCs approve and evaluate prudence of capital costs and determine the generation tariff on an annual basis with a fixed return on equity. The Act also empowers regulatory commissions to award licenses for the trading of electricity. This feature coupled with the delicencing of generation and open access has led to the development of what is termed as ‘merchant capacity’. Unlike projects based on bidding or MoUs, the merchant capacity may not have a pre-identified buyer and is hence dependent on the market. For new thermal plants, which have a high payback period and are mostly expected to operate as base load units, such a mode of commercial operation entails significant risks.

Thermal sector

Since 2006, several states began to procure power based on competitive bidding. Around the same time, the central government also launched the Ultra Mega Power Plants policy (UMPP), under which large scale (4000 MW or more) projects were bid out by a nodal agency which also took on the responsibility of some of the project preparation activities such as acquiring land and securing various clearances. The Power Finance Corporation (PFC) - the nodal agency- undertook bidding for such UMPP projects. By 2011, 16, 000 MW was contracted under the UMPP policy: three UMPPs were awarded to Reliance Power Ltd and one to Tata Power Ltd. Apart from the UMPPs, capacity of more than 26, 000 MW has been contracted on a long term basis under the bidding route by various state DISCOMs. Thus, post E Act, capacity addition got a major boost. The installed coal based capacity has more than doubled from 92 GW in 2008 to about 190 GW in November 2018. In comparison to coal based capacity addition, there has not been much of an increase in the gas based capacity.

The tariffs discovered through these various bidding processes initially appeared to be very competitive than similar cost-plus projects. This gave hope that adopting the bidding route for capacity addition was a step in the right direction. However, demand for post-bidding changes to the discovered tariff, ambiguities in the domestic coal allocation policy, and a lack of adequate coal availability, have mired such perceptions of success. See Box 9.2 for more on competitive bidding based projects.

As on August 2018, around 40 GW of the total coal based installed capacity is identified as stressed, i.e. these units could not pay their interest and/or principal. They account for stressed debts of about Rs 1.8 lakh crore and represent an investment of about Rs 2.3 lakh crore. Out of these 40 GW, projects worth about Rs 34,000 crore have been classified as Non-Performing Assets (NPAs) as of June 2017 - that is, their interest and/or principal has remained overdue for more than 90 days. The major reasons identified by the Parliamentary Standing Committee for the stressed assets were the lack of regular fuel supply arrangements, the lack of PPAs, the inability of promoters to infuse the necessary capital and regulatory and contractual issues.

Most of the lending - almost Rs 4 lakh crore or 83% of total lending to power sector - came from public financial institutions of India. The financing pattern of the stressed assets examined by the Parliamentary Standing Committee is similar - practically the entire capacity is supported by public financial institutions. The build-up of stressed assets and NPAs in the coal-fired power generation sector indicates that the financial institutions’ due diligence processes did not take these into consideration sufficiently, nor did they track these aspects rigorously during the tenure of the loan. See Figure 9.2. The stressed assets story underlines serious failures in due diligence on part of the banking sector, which should not have financed such risky ventures that had no fuel tie-ups. Since the bankers are unlikely to suffer the consequences of these bad loans, the moral hazard and hence public sector lending to projects based on risky fuel arrangements is likely to continue.

Figure 9.2: Public financial institutions financing stressed and non-performing assets

Source: Prayas (Energy Group)

Box 9.2: Competitive bidding and compensatory tariff

In Chapter 7 (refer to 7.2.4) we have looked at the role of competitive bidding in facilitating capacity addition. As has been discussed there, Section 63 of the E Act allows ERCs to adopt a tariff for generation that has been discovered through a transparent bidding process conducted according to the guidelines issued by the central government in this regard. Given the failures of the IPP policy, the bidding framework offered a promising start and during 2006-2012, more than 42,000 MW of capacity was added under this regime.

The contracts signed by developers of these projects - known as Power Purchase Agreements (PPA) - allowed revision of tariff only under two circumstances: change in law, whereby a legal action of a government body or a court imposes any cost (or results in benefit); and force majeure, which implies an unforeseen event that prevents or unavoidably delays the performance of obligations under the contract.

Out of the 42,605 MW contracted through bidding, about 30% was based on imported coal, 27% on domestic captive coal mines, and 43% on domestic coal linkages. Excluding the UMPPs, two of which were based on imported coal, only about 17% (4,324 MW) of the rest of the contracted capacity was based on imported coal, while about 70% (17,730 MW) of it was dependent on domestic coal linkages as the primary source of fuel. The coal linkage based projects relied on the New Coal Distribution Policy (NCDP) of 2007 for quoting the fuel charge. Most of the imported coal based projects were importing coal from Indonesia, which till 2010 allowed fixed price contracts for coal.

In spite of the flexibility of passing various risks transparently to the consumers at the time of bidding by quoting suitable escalation parameters, many of the projects that won the bids chose to quote a fixed tariff for 25 years, thus entirely assuming the fuel price variation risk. Some imported coal based projects even assumed currency variation risks for 25 years by quoting tariff in rupees instead of dollars.

In September 2010, the Indonesian government issued a regulation stating that from then on, all the coal imported from Indonesia would be priced as per the international market price of coal. This increased the price of Indonesian coal. The Indonesian government did not increase royalties or taxes, so the entire increase in coal price would benefit Indonesian mining companies. This changed the economics of projects that had participated in bidding assuming fixed price coal contracts for importing coal. Around 2012, the country was severely hit by domestic coal shortage and CIL refused to sign any new fuel supply agreements, even with projects that had a valid letter of assurance for coal supply from CIL. In 2013, the government through an amendment of the NCDP clarified what portion of the fuel supply agreement would be met through domestic coal and how much would be imported, if needed. However, by this time bidding was already done and most of the linkage based projects that had won the contracts had assumed that they would get 100% of their coal supply from domestic coal and had quoted tariffs accordingly.

As the competitively bid projects approached commercial operation, risks pertaining to fuel supply and price became apparent. The projects started seeking revision of the quoted tariffs on account of fuel related issues. Some of these projects approached the Central Electricity Regulatory Commission (CERC) seeking revision of the quoted tariff on the grounds of factors such as increase in the price of Indonesian coal, shortfall in domestic coal supply, rupee depreciation, etc. The projects argued that if it was not possible to grant them relief under the provisions of the PPA, then the CERC should use its broader regulatory powers and provide relief to make them viable.

While concluding that no relief was possible under their respective contracts, the CERC still chose to use its regulatory powers to grant the projects relief under what it called a ‘compensatory tariff’¹⁰. This altered the risk allocation enshrined in the PPA and imposed the entire burden of fuel price variation on consumers. Following in the CERC’s footsteps, ERCs in several states such as Maharashtra, Uttar Pradesh and Rajasthan, adopted the same approach of revising competitively discovered tariffs and allowing an additional compensatory tariff. Thus, even in the absence of any possibility of relief under the PPA, the ERCs began using their regulatory powers to grant compensatory tariff.

The compensatory tariff order of the CERC was challenged before the Appellate Tribunal for Electricity (ATE), and subsequently, before the Supreme Court, which in 2017 rejected the use of regulatory powers to alter tariffs or any provisions of the PPA, so long as the bidding guidelines and the PPA specifically dealt with such issues.¹¹ This is a very crucial judgement as it upholds the sanctity of contracts while not taking away the discretionary power of the regulatory commissions, if it is needed in a situation where the contract or the supporting legal and policy provisions are silent or inadequate. Rejecting any relief for imported coal based projects, the judgement held that the amendment to the NCDP made in 2013 should be considered as a change in law event. It is to this limited extent that it granted relief to projects that were impacted by shortfall in the domestic coal supply after the July 2013 amendment of the NCDP.

For a sector mired with ad hoc changes to the contract post-bidding, the Supreme Court judgement put the necessary check on such discretionary use of regulatory powers. It also strengthened competition by enforcing the rule of law and holding the bidders and lenders accountable for the risks they had willingly taken to win the contracts. The clear and accountable mechanisms upheld by the judgement will not only discourage aggressive bidding based on risky fuel arrangements in future, but it will also lead to more realistic tariff discovery for future projects, which would provide more realistic price signals for the sector at large.

Hydropower sector

Although the 2006 competitive bidding guidelines apply to hydropower, unlike thermal generation, private sector interest in large hydropower projects has been lukewarm. Given its peculiar characteristics such as high fixed costs, large social and environmental impacts on account of huge land requirements, and uncertainty regarding ultimate cost and generation, the 2008 Hydropower Policy specifically exempts large hydropower from the requirement of competitive bidding for tariff discovery.¹² Instead, it allows regulatory commissions to determine the tariffs of private hydropower projects on a cost-plus basis. To qualify for this, the projects have to fulfil certain conditions such as undertaking international competitive bidding for equipment purchases, and entering into a long term PPA for at least 60% of the saleable energy. However, a regulated cost-plus tariff based approach has meant significant cost overruns and ever increasing tariffs. To make matters worse, many projects have consistently failed to generate at the levels assumed for project approval.

As on December 2018, the country has installed hydro power capacity of around 45 GW out of which, about two-third (66%) is with the state sector, 27% is with the central sector and only 7% is with private sector. As per the government reply before the Parliament in March 2017, out of 44 hydropower projects under construction, 20 projects totalling 6,329 MW are stalled or stressed and an amount of Rs 30,147 crore has already been spent on these projects.

Thus, it is clear that in spite of more than 25 years of reforms, the hydropower sector is far from achieving any real competition or operating on market-based principles. On the contrary, the enhanced incentives (ultimately paid for by the taxpayers) and insulation from all forms of risks (in the form of regulatory certainty and cost-plus tariffs), which are increasingly shouldered by the state or the public, has bolstered private participation in the sector - though its outcomes still at best, are uncertain.

Renewable Energy

In the decade following the E Act, the direct costs of renewables were much higher than conventional power. Hence, the policies regarding renewable energy were focussed on cost reduction on the one hand, and protecting the growth of the renewable energy sector on the other. These measures were to be carried out through various policy-regulatory instruments as long as there was a continued lack of a level playing field for renewables, i.e. the costs of socio-environmental externalities of conventional power were not internalised.

Important reforms, which initiated a second growth phase in the renewables sector from 2003 to 2010. Under these reforms, technology-specific preferential tariffs (i.e. cost-plus feed-in-tariffs) along with minimum renewable energy purchase targets for all obligated entities such as DISCOMs, open access and captive consumers, were introduced. While there have been lapses in strict compliance with such minimum purchase obligations by all states, it has helped some states with good wind potential, like Tamil Nadu and Maharashtra, to add significant amount of renewable energy based capacity.

The biggest push for renewables came with the launch of the National Solar Mission in 2009 and the change in the solar pricing methodology from regulated feed-in-tariffs to those discovered through competitive bidding. Competitive bidding in photovoltaic (PV) solar has been successful so far. The solar tariffs discovered in 2010 were more than Rs 12 per unit, but have fallen to about Rs 2.5 per unit in the recent rounds of 2017-18. The wind industry has been largely vertically integrated and averse to competitive price discovery till 2016. However, since 2017, wind procurement has begun to be undertaken through bidding and the rates discovered are fairly competitive.

Unlike the thermal sector, the renewable sector seems to have healthier competition among a significant number of players and has witnessed rapid reduction in the discovered tariffs. Also, so far, there has been no litigation demanding post-facto contract revision.

Current status of generation

Figures 9.3 to 9.6 provide a macro picture which captures the changes in the generation fuel mix, generation ownership and consumer mix from 1990 to 2018.. Figure 9.3 shows the percentage fuel mix in generation capacity in 1990 and 2018. The installed capacity increased from 64 GW in 1990 to 344 GW in 2018 - an increase of more than five times. The domination of coal has reduced only slightly, but there has been an impressive growth in renewable energy based generation capacity. Renewable capacity has crossed the hydropower capacity in April 2016 and will further increase due to the initiative to reach 175 GW renewable capacity by 2022. Contribution of hydropower has reduced, while that of gas has marginally increased, and that of nuclear has remained the same. This capacity does not include around 55 GW of captive power capacity.

Figure 9.3: Generation capacity-fuel mix 1990 and 2018

Source: CEA monthly report on installed capacity for March 2018

Figure 9.4 shows the percentage ownership of the generation capacity by the centre, states and private players. The state governments were the major owners in 1990, whereas in 2018, the private sector owned most of the generation capacity. The role of the central sector has remained the same between 1990 and 2018. More than half of the thermal capacity added during 2003 to 2018 is owned by the private sector while renewable capacity is almost completely owned by the private sector. This trend of an increasing role for the private sector is likely to continue in general and particularly in the renewable sector.

Figure 9.4: Generation capacity-ownership mix in 1990 and 2018

Source: CEA monthly report on installed capacity for March 2018

Figure 9.5 shows the percentage fuel mix in electricity generation in Billion Units (BU) in 1990 and 2018. While the domination of coal and the contribution of renewables, gas and nuclear power has increased between these years, the share of hydropower has reduced. It can be seen that the percentage contribution of coal based generation is higher than its percentage share in capacity. For hydropower, gas and renewables, the percentage generation is lower than percentage capacity, since they generate electricity only when water, wind or sunlight is available.

Figure 9.5: Generation-fuel mix 1990 and 2018

Source: CEA executive Summary for the month of March 2018 and CEA annual report for 2017-18

Figure 9.6 shows the percentage ownership mix in generation in 1990 and 2018. Similar to the trends in capacity, the contribution of the state sector has reduced, that of the central sector has marginally increased, and that of the private sector has increased significantly.

Figure 9.6: Generation-ownership mix 1990 and 2018

Source: CEA executive Summary for the month of March 2018 and CEA annual report for 2017-18

9.3.3 Distribution sector

Several changes have taken place in the Indian electricity sector in the last three decades. It is not possible to comprehensively discuss and detail out the same in this chapter. Some of the important changes are briefly discussed below.

Almost all SEBs have been unbundled to form corporations, Electricity Regulatory Commissions have been set up, distribution privatised in Delhi and urban franchisees set up in many cities. Restructured states typically have one or more distribution companies, one state owned transmission company and one state owned generation company. Some states also have private generation and distribution companies. There is variation in the number and nature of companies set up in different states.

After the Delhi privatisation experience, a different model for distribution privatisation has been introduced, called the input based distribution franchisees. This has been explained in Box 5.4 Input-based distribution franchisees. Under this model, some aspects of the distribution business in certain areas, especially urban high loss pockets, are awarded to private entities for a limited period based on bidding. These franchisees are selected based on the loss reduction trajectory and revenue sharing. For the given area and the given period, the franchisees are effectively the distribution companies and are required to perform all duties of a DISCOM. Consumers in franchisee area pay the same tariff as the rest of the DISCOM consumers in that state.

The experience with franchisees has been at best mixed and even disastrous in some cases. The first such input based franchise was awarded to Torrent Power Limited (TPL) in 2007 for Bhiwandi. Since then many contracts were awarded to other private players in other cities in Maharashtra, and they are all fraught with issues. The problems range from bidding itself, to delays in takeover of franchisee areas by the private company as well as post-bidding dilution of contracts. In many cases, the delay in takeover of the operations was for such long periods that the DISCOMs terminated the agreements. As per the CAG report in the case of Torrent Power Limited’s Agra franchisee, the baseline AT&C losses reported for the bidding process was 10% higher than the audited actuals.¹³

Under the E Act, open access, i.e. non-discriminatory access to use the network, has been made mandatory in a phased manner in transmission and distribution. Any transmission or distribution company had to make its infrastructure available at a charge to anyone who wanted to use it to transfer electricity. Open access has made it possible for power generators to sell power directly to consumers and for the big consumers to access power from the generator of their choice. Power trading, which means purchase and sale of electricity, is recognised as a separate activity under the E Act for which licenses are granted by the ERCs. This has also enabled the establishment of power exchanges, which are more transparent and specialised platforms for power trading than bilateral contracts.

Figure 9.7 shows a simplified schematic of the state level power sector as envisaged under the E Act. The distribution company procures power from various sources, including state, central and private generation companies. Some of the big consumers, like say those with connected load greater than or equal to 1 MW, also have the freedom to choose their supplier and can procure power under open access either directly from the generators or through traders or exchanges. As discussed in Chapter 7, such open access consumers have to pay the distribution and transmission company charges for using their wires network. These are called wheeling charges. Apart from the wheeling charges, these consumers also have to pay cross-subsidy, electricity duty and any other surcharges as may be notified by the state ERC.

Figure 9.7: State level power sector after the E Act

Source: Prayas (Energy Group)

The E Act elaborated the role of the Electricity Regulatory Commission (ERC) at the central and state levels. The central ERC was to issue licenses and fix tariff for all multi-state operations. The state ERC was responsible for monitoring the state companies, fixing consumer tariff and approving investments. The E Act mandated the SERCs to increase transparency in the operation of the sector and provide opportunities for public participation. As a pro-consumer measure, the E Act made it mandatory for distribution companies to notify standards of performance and set up consumer grievance redressal forums. The E Act mandates that all retail sale of electricity should be metered and has strict provisions for discouraging power theft.

In 2006, the National Tariff Policy was notified by the Indian government, which laid down the framework for fixing tariff for generation, transmission, and distribution companies and for consumers. Minor amendments to the policy have been made, and a new amended Tariff Policy was brought out in 2016.¹⁴ This policy has provisions to promote renewable energy, facilitate 24 x 7 power for all, pass on the impact of change in the cost of coal to the consumer, and to introduce a time-of-the-day tariff while also advocating for open access consumers to bear the cost of stranded capacity.

Figure 9.8 shows the percentage electricity consumption mix. Electricity consumption increased from 195 billion units (BU) in 1990 to 1130 BU in FY 2017-18 (estimated) - an increase of 5.8 times.¹⁵ The share in consumption of industry and agriculture consumers has reduced, whereas that of residential and commercial consumers has increased. This is on account of multiple factors such as the growth of the services sector, an increase in the number of middle class households who are also consuming more, increasing household electrification and improved energy efficiency in the industrial sector. The per capita electricity consumption increased from 329 units/year in 1990 to 1149 units in 2017-18.¹⁶ It is another matter that India’s per-capita consumption is still one-third of the world average.

Figure 9.8: Electricity consumption mix 1990 and 2017-18 (estimated)

Source: CEA report “Growth of Electricity Sector in India from 1947 - 2018”

As for tariff movements, for many years after independence, the tariffs for industry and agricultural consumers were kept low compared to those for commercial and domestic consumers. This was done to encourage industry and agriculture. As discussed in Chapter 7 (refer section 7.4), once the reforms were set in motion, the tariff of domestic and agriculture consumers went up, but still remained below the average cost of supply. The commercial tariff has increased significantly (around 30% higher than average cost of supply) while the industry tariff is nearly equal to the average cost of supply.

It is to be noted that since 2015-16, the shortages have reduced substantially and, in fact, there is significant unutilized generating capacity. There were severe shortages in 1990s, with 16.66% peak shortage and 7.92% energy shortage. The energy shortage was 0.7% while the peak shortage was 2.1% in 2017-18. The CEA has anticipated a power surplus for in 2018-19, with a 4.6% energy surplus and a 2.5% peak surplus.¹⁷ This is indeed an interesting development, though the power situation is different in different states, with many states still suffering shortages. The CEA uses historical trends to estimate demand and does not account for latent demand. The availability of power does not automatically lead to an increase in consumption, especially if the power is costly. In fact, it is already leading to the backing down of generation, with distribution companies having to pay the capacity charges, leading to higher consumer tariffs. More on this issue is discussed in Chapter 10.

Rural Electrification

There has been a significant progress in village electrification and providing electricity connections, especially from 2005, when Rajiv Gandhi Grameen Vidyutikaran Yojana (RGGVY), the massive national rural electrification programme was launched. This programme has been revised over the years and is called Deendayal Upadhyaya Gram Jyoti Yojana (DDUGJY) from 2014. These programs covered village electrification, providing free connections to rural Below Poverty Line (BPL) households and strengthening rural distribution infrastructure. Pradhan Mantri Sahaj Bijli Har Ghar Yojana (Saubhagya), another program to electrify Above Poverty Line (APL) and urban households was launched in 2017.¹⁸

Out of the Rs 1 lakh crore sanctioned, around Rs 55,000 crore have been invested over the last 15 years in rural electrification. Nearly 1.3 lakh villages and 12 crore households (rural and urban, BPL and APL) have been electrified. Government has reported 100% village electrification in April 2018 and 99% household connections by end 2018.¹⁹ There has been steady progress in connections, but significant work towards rural distribution strengthening is yet to be completed. The quality of electricity supply to rural areas still remains poor with low hours of supply and many outages. The ongoing ‘Power for All’ programme proposes to provide 24 x 7 power to all by 2019 or 2022.²⁰ This is very much desirable, but if this ambitious goal is to be achieved, it is important to focus on affordable, sufficient, quality electricity supply, especially to the small consumers, and to promote productive use.²¹

Since 2000, four central sector programmes have been implemented to ensure AT&C loss reduction. All these programmes had an urban focus and aimed at loss reduction through large investments in network augmentation and system upgradation. A brief description of these programmes is provided in Table 9.1. In spite of such attention, transmission and distribution losses, one of the key indicators of efficiency, remained more or less the same - 23% in 1990, which went up to 34% in 2002 (largely due to better reporting after the introduction of regulatory commissions), and in 2016-17 were reported to be 21%. Supply to agriculture pumps, which accounts for 20%-30% of total sales in most states, continues to be largely unmetered, raising concerns regarding the veracity of the loss figures.

Table 9.1: Loss reduction programmes

Source: Scheme-wise details published by the Ministry of Power and all India sanctions and disbursements for sub-transmission & distribution as published on the Integrated Power Development Scheme (IPDS) portal http://www.ipds.gov.in/

Financial turnaround of distribution was one of the key objectives of reforms, however, financial losses of distribution companies have kept on increasing and three central government supported bailout plans have been implemented between 2001-2015. All of these schemes, including the latest Ujwal Discom Assurance Yojana (UDAY) rolled out in late 2015, are very similar in design. In each scheme, the state government takes over a major portion of the past liabilities by issuing long term bonds through banks and other financial institutions. It is imperative that the state government takes over the debt, as the state owned DISCOM is its responsibility. Additionally, unlike DISCOM bonds, there is a higher appetite and confidence in the market for state government bonds which have the sovereign’s commitment to repay them. The previous two bailout schemes financed past liabilities and did not account for any mechanism to finance losses that the DISCOMs are likely to incur during the transition period. UDAY is different from past schemes as it plans for the state government to finance not just past liabilities but also losses incurred in the future. Under UDAY, future losses are to be taken over in a progressive manner in perpetuity. If implemented, this will increase accountability of state governments to ensure efficiency improvements in the DISCOMs. 27 states have signed up for UDAY, as of end 2018.²²

All three bailout schemes were voluntary with participating state governments and DISCOMs agreeing to comply with the specified conditions and meeting performance targets in a time-bound manner. Some of the conditions with respect to AT&C loss reduction, power procurement planning, and the moratorium on short term lending have been discussed earlier in this section. The condition of ensuring sustained tariff increase is another highlight of these schemes. Often, these conditions did not come with achievable milestones or support. Compliance in all schemes was to be monitored by the central government on a regular basis, and incentives or penalties were to be awarded based on performance. The current UDAY scheme has similar conditions and more ambitious timelines than the past two schemes, as it plans to eliminate revenue gaps by 2019 and reduce AT&C losses from unsustainably high levels to 15% with metering drives and measures to improve revenue collection.

Efforts to introduce major changes in the Electricity Act 2003 have started since 2012. A draft bill was introduced in the Lok Sabha in 2014. After subsequent modifications and recommendations made by the public and the parliamentary standing committee on energy, a revised draft has been published in September 2018 for seeking further comments from the public. The bill is yet to be tabled in the Parliament. The major amendments proposed are to provide the choice of power supplier to even small consumers, thus bringing competition to the retail level. Amendments suggested include the creation of separate electricity supply companies (called separation of distribution and supply or carriage and content separation), further promotion of open access, increased encouragement of renewables, and strengthening provisions for regular tariff revisions. Anticipating a greater space for competition and a multiplicity of supply options, the amendment aims at introducing ancillary services, spinning reserves and enforcing greater discipline in grid management. It also proposes major changes in the selection process of the regulatory commission members and chairperson, their term of office, etc., while also putting in place mechanisms for performance reviews of the commissions.²³

9.3.4 Electricity transmission

The transmission sector has been largely owned and operated by the government, except in a few urban pockets like Mumbai and Kolkata. After SEB unbundling, there was one transmission company in each state, and POWERGRID handled all inter-state transmission at the national level. According to the Electricity Act 2003, the central government was to notify a government company as the Central Transmission Utility (CTU), and the state government was to notify a government company as the State Transmission Utility (STU). Accordingly, POWERGRID, a central government public sector company, is the CTU and the state transmission companies are the STUs. Load dispatch function was to be separated from transmission. This has happened at the national level when the Power System Operation Corporation (POSOCO) was separated from POWERGRID in 2017, but there has been inordinate delay in separating load dispatch from the STUs.

The whole country is now connected to one grid and the operation of the inter-state grid has improved with many initiatives of CERC, including the Indian Electricity Grid Code. In most states, the DISCOMs continue to function under the overall guidance of the transmission company. This includes management decisions and power purchase.

In the last two decades, this sector has been the slowest in moving out of state ownership. According to the E Act, guidelines for tariff based competitive bidding for transmission have been notified by the central government in 2006. Likewise, standard bidding documents for public-private-partnership based projects (2007), and the Model Transmission Agreement (2010) have been prepared under the Planning Commission’s task force on policy and regulatory framework for private participation in transmission. Subsequent to this, in 2010-11, the CERC approved 11 high capacity transmission projects, mostly private sector owned, totalling to investments of about Rs 75,000 crore. In 2015-16, transmission projects worth nearly Rs 1 lakh crore were awarded through competitive bidding, with POWERGRID winning projects worth Rs 56,000 crore and private players winning projects worth Rs 35,000 crores. According to the CEA, there are plans to bid out projects worth nearly Rs 50,000 crores in 2016-17. Draft of Standard Bidding Documents for intra-state transmission projects was released in 2017. Green energy transmission corridors are being planned to evacuate renewable energy power. As indicated in Table 5.2 in Chapter 5, presently, private participation in the transmission sector (in circuit kilometres) is low at around 7%, but the trend indicates a likely growth in this share.

The National Electricity Policy and Tariff Policy mandate that the national inter-state transmission tariff framework should be sensitive to distance, direction and quantum of flow. Accordingly, the CERC in 2010 notified the regulations for the sharing of inter-state transmission charges among various grid users. The method described in the regulations is known as the Point of Connection (PoC) tariff. This approach has some limitations and to overcome these, General Network Access (GNA) is expected to be adopted soon. The idea is that the generator and the consumers could be given GNA to the Inter State Transmission System for the agreed quantum of power (MW). It is expected that the GNA agreement could become a driver for private investment.

Close coordination with generation capacity addition and demand growth is a major challenge. The number of multi-state private generating plants and their capacity has been increasing, with many of them operating as merchant plants without any long term contracts. Growth in markets and renewable generation has introduced many unknowns in actual power flows and hence the capacity utilisation of the transmission sector. The national grid is still not able to cater to the needs of inter-regional power flows, though it is expected to be fully equipped to do so soon. While there are reports of transmission congestion in some areas which are preventing the smooth transfer of power, there are also reports of underutilisation in other areas. Ensuring grid security and high utilisation of installed capacity are conflicting requirements and a proper balance is yet to be established.

The transmission capacity is based on the permissible rise of conductor temperature, whereas the transfer capacity depends on the dynamic parameters of the grid, like voltage, generation and required reserve margins. Congestion occurs when the required amount of power to be transmitted is more than the available transfer capacity. The CERC had noted in 2015 that the available transfer capacity (decided by the Load Dispatch Centre) is often 20%-30% of the transmission capacity, and has been leading to congestion in many areas, thus reducing power transfers. Real time modelling of the grid and quick corrective actions are required to reduce congestion. Ensuring proper power transfers, open access and market operation is therefore a big challenge.

As discussed in Chapter 8 (refer to section 8.1 on Integrated Resource Planning - An ideal approach), transmission grid helps to optimise generation resources and to improve system reliability. However, at the national and state levels, planning for the transmission sector is difficult because of poor load forecasting and planning for generation capacity addition. Use of short term open access by many generators, forming long term access agreements for transmission without long term power purchase contracts, growth of renewable capacity (which has shorter gestation periods compared to transmission systems and whose power generation cannot be perfectly predicted), backing down of generators, and short term markets (which also introduce uncertainties in power flows) pose challenges to transmission planning. If we are not able to face these challenges, there is the danger of underutilisation of transmission assets.

Similar to conventional generation projects, setting up of transmission lines also needs significant tracts of land, which often leads to protests at the ground level. Table 3.3 in Chapter 3 has provided approximate amount of land required under the transmission lines, called right of way. Recently, a number of cases have been filed before the various state ERCs and the CERC concerning disputes regarding compensation for the right of way as well as the process of land acquisition. Unlike conventional generation projects, cultivation of crops (with low height) is possible below the transmission line, but people feel that is not very easy. Given the very high voltage of these lines, safety is also a big concern. Additionally, it is believed that the market value of such land reduces, which makes farmers reluctant to part with land. There have been demands for more transparency in the land acquisition process and ideas like paying rent to the landowner instead of a one-time compensation have been suggested.

Blackouts have shown that unregulated grid operation can cause extensive damage to vast populations. With the steep rise in generation capacity in the recent years and considering the capacity addition plans for future, it is imperative to have a robust transmission grid that can reliably carry this power to the load centres, i.e. areas where it is needed. For this to happen, apart from detailed and careful planning of the transmission sector, there is also an urgent need to develop processes and mechanisms to address the various implementation challenges listed above. In the transmission sector, most of the policies, regulations and guidelines are prepared at the national level, and participation by civil society actors in these processes has been limited. This is not a good sign, since the next decade may witness the opening up of the transmission sector with many private players and increased complexity of grid operation. If sufficient checks and balances are not put in place in the planning and operation of the grid, there are dangers of underutilisation of investment and more blackouts.

9.4 Brief overview of reforms in related sectors

Generation cost is one of the most crucial parameters for electricity tariff, as it accounts for more than 70% of the cost of electricity supply. In case of thermal generation, fuel related costs account for more than half of the generation tariff. As the figures 9.3 and 9.5 highlight, coal based thermal generation has been the mainstay of the Indian electricity sector. Natural gas is the second most used fossil fuel in power generation and fuels about 8% of India’s installed capacity. However, since India only owns about 0.8% of the world’s natural gas reserves and given the limited exploration of its sedimentary basin thus far, India imports a significant amount (almost 40%) of its natural gas requirement.

Much like the other infrastructure sectors, coal and gas are also capital intensive sectors with long gestation periods, high production risks and significant impacts on other scarce resources such as land, water and forests. They also have serious environmental and social impacts. Besides fuelling the country’s power sector, these are crucial sectors in their own right and are essential to meet the country’s overall energy demand. However, the brief overview of these sectors provided here is limited to viewing them as crucial linkages for the electricity sector. An in-depth analysis and review of the reforms in these sectors is beyond the scope of this primer.

9.4.1 Coal sector reforms

The coal sector in India was nationalised in the early 1970s to improve mining practices, protect labour interests, increase efficiency, and hence production. Following this, the public sector coal mining behemoth Coal India Ltd (CIL) was born, and India’s coal production gradually increased from 80 million tonnes per annum (MTPA) in 1972-73 to 259 MTPA in 1992-93. Apart from CIL and its subsidiaries, the Singareni Collieries Company Limited (SCCL) is the only other coal mining company in the country, which is jointly owned by the Telangana government and the central government, and which accounts for about 10% of total coal production.

After the nationalisation of the coal sector, coal was allocated to consumers, including power plants, by the Ministry of Coal (MoC) in the form of ‘linkages’ based on which CIL would supply coal to consumers. In 1993, power was notified as an end-use of coal for which captive coal blocks could be allocated. As a result, power companies could not get a coal block from which they could extract coal for their power plants.

In a surprising move, coal pricing was completely deregulated in 2000. This allowed CIL and SCCL to set prices without any independent scrutiny for prudence, though the government continued to regulate the prices in a de facto mode. It is interesting to note that in spite of a move to explicitly deregulate pricing of a commodity exclusively owned and managed by monopolies, the idea of an independent regulator to oversee pricing and operations in the coal sector did not get much attention.

As of the early 2000s, there were two routes available to a coal consumer for obtaining domestic coal. The first was through the ‘linkage’ route and the second was to be awarded a coal block for captive use. Much like the IPP policy, in spite of the tremendous interest shown by the private sector in securing captive coal blocks, they were allocated without bidding, through an ad hoc process overseen by a committee. Similarly, till 2007, there was no well-defined policy governing allocation of coal linkages.

Following a directive from the Supreme Court, the government in 2007 notified the New Coal Distribution Policy (NCDP) for allocating linkages. It promised 100% domestic coal allocation through linkages to new plants. This policy also stated that if domestic coal production was inadequate, coal would be imported to meet such shortfall, and the price of such imports would have to be entirely borne by the buyer i.e. the power generator. However, from a plain reading of the policy it was not clear how much part of the coal supply was assured from domestic coal and to what extent imports would be necessary for a given project. The distinction between domestic and imported coal is important because of the significant price difference between them, which in turn, would impact the viability of the power generation project. With this glaring ambiguity regarding the source of coal for each linkage, to make matters worse, linkages were granted far in excess of CIL’s ability to produce coal. This led to convenient (and contradictory) assumptions by coal suppliers and consumers.

A few years subsequent to the introduction of the NCDP, India faced a huge coal shortage and the power projects clamoured against CIL’s inefficiencies and monopolistic practices. As coal-fired capacity went up from 76 GW in March 2008 to about 165 GW in March 2015, steam coal production (coal used by the power sector) went up by only about 30% from 423 million tonnes per annum (MTPA) to 552 MTPA. This disjointed development of two closely related sectors, power and coal, led to country wide coal shortages. As a result, imports of coal by the power sector increased from about 10 million tonnes (MT) in 2007-08 to over 90 million tonnes in 2013-14.
Apart from the allocation issues, there are also been issues in terms of planning to ensure adequate evacuation facilities for the coal that is produced. This adds another layer of ambiguity to the coal shortages and allows all entities that is, coal companies, power companies and railways, to point fingers at each other and thus obfuscate the entire issue.

Belatedly, in July 2013 the government clarified the ambiguity by modifying the NCDP to explicitly state how much coal would be supplied from domestic sources and how much would be met through imports. However, by this time bidding for more than 42 GW of power capacity had taken place and contracts had been already signed. More than two-third of these projects relied on domestic coal linkages as the primary sources of fuel. This led to huge amount of litigation seeking change in quoted tariff and ultimately the Supreme Court judgement in 2017 which recognised the 2013 NCDP amendment as a change in law event (refer Box 9.2).

In May 2017, the government took two important decisions regarding the coal sector. The first one is that it directed the coal companies to sign FSAs with all power plants that have a valid letters of assurance (LoAs) and are likely to be commissioned by March 31, 2022. The second one is the notification of a policy called SHAKTI (Scheme for Harnessing and Allocating Koyala Transparently in India) to streamline coal allocation to the power sector and making it more transparent and objective. Estimates suggest that about 44 gigawatts (GW) of coal-fired capacity that already has LoAs can now sign FSAs, and about 27 GW of this may already be commissioned. Since this 44 GW will fall under the old regime, SHAKTI is likely to be applicable to the roughly 50 GW of capacity that is in the pipeline and expected to be commissioned by 2022 according to the draft National Electricity Plan (NEP) from the CEA.

On the captive block allocation front, over 200 coal blocks containing about 50 billion tonnes of reserves were allocated between 1993 and 2010. In its audit, the CAG found that blocks had been allocated to aspirants based on very weak or ad-hoc criteria.²⁴ The captive blocks were given to private (and public) sector companies with no conditions attached. Thus, there was no need for them to pay any additional royalty or other amount to the government, nor was there a requirement for them to pass on the benefits of receiving this ‘free resource’ to their consumers. The CAG estimated that, as a result, the private sector stood to make windfall gains of around Rs 1.8 lakh crores. Even worse, the possibility of such undue gains was pointed out at a meeting of the screening committee by one of the states, but the committee did not act upon it.

Based on the CAG report, a Public Interest Litigation was filed in the Supreme Court. In an extraordinarily strong judgement, the Supreme Court cancelled most of the block allocations since 1993 and also made some scathing observations on how the allocations were made. ²⁵ Following this coal block cancellation order in 2014, the government issued ordinances that were subsequently passed as the Coal Mines (Special Provisions) Act (CMSPA) to facilitate the reallocation of cancelled blocks. Based on the ordinances and this Act, the government allocated around 70 coal blocks for captive consumption through auctions and allotments by early 2016. After the aggressive bidding for the first two rounds of block auctions, interest in acquiring coal blocks has waned considerably. The government has been talking about initiating commercial mining of coal, but the current policy plan is unlikely to garner much interest.

9.4.2 Gas sector reforms

Oil and gas production was a relatively small private sector enterprise at the time of India’s independence. Efforts to involve private participation in this sector began in the late 1970s but weren’t successful in attracting significant interest or funds. Subsequently, between 1992 and 1993, small and marginal fields that were already discovered were offered for development to private operators over three bidding rounds. A further six rounds of bidding were offered for exploration between 1991 and 1995 and onwards during which 27 exploration blocks were awarded. Concurrently, the Directorate General of Hydrocarbons (DGH) was set up in 1993 under the Ministry of Petroleum and Natural Gas (MoPNG) to regulate various aspects of upstream oil and gas activities such as licensing, safety, development, conservation and reservoir management.

It was felt that exploring and exploiting India’s unexplored reserves requires the deployment of sophisticated technology and global best practices. Hence, the objective of reforms in hydrocarbon exploration and production has been to attract risk capital, geological expertise, state of the art technologies and management practices. In this context, the New Exploration Licensing Policy (NELP) was introduced in 1999 to facilitate open international competitive bidding. Under this policy, 100% Foreign Direct Investment (FDI) is allowed and private as well as state owned oil companies compete to secure exploration licenses under the same financial and contractual terms. Contractors are free to sell gas produced under the NELP in the domestic market, at market or ‘arms-length determined’ prices. However, in spite of all these efforts, only a small portion of India’s sedimentary basin was explored till 1999. Under NELP, acreages were granted to public and private companies based on a competitive bidding process.

Some of the early discoveries under the NELP process gave cause for optimism that India could rapidly ramp up domestic gas production. It also resulted in significant addition to gas-based power generation capacity in some states like Andhra Pradesh. However, as of 2016, NELP contracts have not resulted in any significant sustained increase in domestic gas production, and in spite of international competitive bidding, not many players are interested.

In comparison to coal based capacity addition, there has not been much of an increase in the gas based capacity. As of November 2018, the total gas -based installed capacity in the country is about 25 GW, of which roughly 14 GW has been totally idle. Out of the idle capacity of 14 GW, roughly 11 GW is owned by the private sector. Out of the capacity that is running, only 3 GW belongs to the private sector. Load factor of the plants that were operational is also low at around 30%.

Most of the gas based capacity remains stranded for want of fuel, as generation based on imported gas is still very expensive. In the future, if international gas prices fall and/or bidding for electricity during peak hours becomes prevalent, some of this capacity may get utilised. As of now it faces the prospect of turning into NPAs. To utilise some of these plants, the government in 2015 introduced a subsidy scheme to make generation based on imported gas viable. While it helped a few projects to generate some power, the fact remains that most of the gas-based capacity is largely unutilised, blocking crucial resources which could have been put to better public use.

Table 9.2: Major changes in the electricity and related sectors since 1990

Area

Pre-reform, before 1990

Current status

Utility structure

Integrated SEB, with the functions of generation, transmission and distribution

Most SEBs unbundled into generation, transmission and distribution companies

Ownership pattern

Mostly with the government - central or state

Large presence of private players in generation, moderate presence in distribution, growing presence in transmission

Policy

Policy making largely by state and central governments. Electricity considered a major development input

In policy making, influence of international funding agencies during the beginning of reforms, increasing role of central government and private players in subsequent years. Electricity transitioning towards a market commodity

Electricity regulation

Directly by the central and state governments

By regulatory commissions appointed by the central and state governments

Electricity markets

Not present

Increasing role of markets facilitated by open access, trading, merchant power plants and power exchanges.

Competitive bidding, a market feature has been introduced in areas like franchisees, coal allocation, and capacity addition in generation and transmission.

Renewable energy

Very less, only small hydro, small pilots - not connected to grid

Significant rise in capacity and generation. Capacity added mostly through bidding and by private sector. Ambitious plans going forward.

Energy efficiency

Small state level pilots

Large national initiatives, but impacts not clear

Coal sector

Supply by government owned companies

Growth in production, but shortages and imports persist. Some attempts at privatisation, linkage auctions, commercial mining, and regulation. Ambitious targets for increasing domestic production and reducing imports

Gas sector

Few government companies, moderate imports

High imports, few private companies also, regulation for downstream.

Source:Prayas (Energy Group)

9.5 A short summary of reforms

The last three decades since 1990 have seen many twists and turns in the policy framework and structure of the Indian power sector. Some of these changes, such as the increase in generation capacity, the rapid increase in uptake of renewable energy sources and near universal access to electricity are desirable. If sustained in an appropriate manner, these changes can help to achieve broader goals of economic and social development. However, one cannot help being disappointed about the tedious ways in which the positive changes have come about, and the many policy, regulatory and institutional failures that could have been avoided while achieving them.

Serious concerns about the financial viability of the sector persist, with the continued precarious situation of the electricity distribution companies. India’s energy import dependence has been steadily rising and there are also increasing concerns around pollution resulting from the energy sector. Thus, the sector still faces many serious challenges in spite of over two and a half decades of reforms. Table 9.2 summarises the major changes that have taken place since 1990.

Looking ahead, due to the falling prices of renewable energy sources and the growing pressure due to climate and fuel availability challenges, wind and solar energy is set to play a much bigger role in shaping the sector economics as well as grid operation. The changing economics of renewable energy and the increasing ease and modularity of these sources will boost open access and consumer migration in many ways. While a greater role of renewables is a welcome change for environmental sustainability, in the short run, it can create serious challenges for the already precarious state of utility finances. The national grid needs to be strengthened in capacity and operation to support this growing renewable capacity, market operations and inter-regional electricity flows. However, in light of the many challenges discussed so far, alas it remains doubtful that the programmes such as 24 x 7 Power for All by 2019 and UDAY, designed to address the financial losses of distribution companies, will succeed in meeting their objectives.

To conclude, the country today faces the difficult challenge of balancing its need to provide all its citizens with clean, modern energy services given the highly limited natural resources available, increasing social and environmental problems, and constraints imposed by climate change. Unfortunately, we are inadequately prepared for dealing with this multi-dimensional challenge due to policy, planning and governance deficits. In addition to these challenges, technology is enabling large scale integration of renewables in a way that was difficult to imagine even a couple of years ago. The rapid rise of renewables coupled with a regulatory and policy regime that promotes open access at the cost of the utility’s financial health may lead to more supply options for the rich and high-paying consumers. However, the rural consumers and the poor will have to continue to depend on the cash strapped distribution companies and thus, ultimately suffer the adverse consequences of such a transition. These fears are amplified in light of the proposed amendments to the E Act, which seek to institutionalise a greater choice for large and high-paying consumers.

Endnotes

¹ Many Sparks but Little Light: The Rhetoric and Practice of Electricity Sector Reforms in India, Prayas, 2018. Available at: http://prayaspune.org/peg/publications/item/332-many-sparks-but-little-light-the-rhetoric-and-practice-of-electricity-sector-reforms-in-india.html

² The electricity sector was previously under the Ministry of Energy Sources. The Ministry of Power was set up in 1992.

³ The promotion of renewable energy came within the ambit of the Commission for Additional Sources of Energy (CASE) set up in 1981, the Department of Non-Conventional Energy Sources (DNES) in 1982, and the Ministry of Non-Conventional Energy Sources (MNES) in 1992. In 2006, the MNES was renamed the Ministry of New and Renewable Energy (MNRE).

⁴ These 9 states are Odisha, Haryana, Andhra Pradesh, Uttar Pradesh, Karnataka, Rajasthan, Delhi, Madhya Pradesh and Gujarat, which passed Electricity Reform Acts between 1996 and 2003.

⁵ In 1992, the installed capacity was about 70,000 MW.

⁶ August 1996, the Ministry of Power, Government of India set up a committee headed by former Chairperson of the CEA, Shri M.K. Sambamurti, for “promotion and development of hydroelectric projects in the private sector”. Analysing the reasons for the lukewarm response of the private sector, the committee placed it in the context of the overall decline in the growth of hydropower in the country, including public sector hydro projects. The committee report notes that “hydropower development had a serious setback in the Fourth Plan (1969-1974) and it never recovered from it” (Central Board of Irrigation and Power, 1997).

⁷ For more details regarding the early developments in the Enron saga, refer to Abhay Mehta’s book titled “Power Play: A Study of the Enron Project” published in 2000 by Orient Blackswan. Two other publications that can be helpful for understanding the socio-political as well as techno-economic aspects of the controversy are: a) The Enron Story: Controversial Issues and the Struggle http://www.prayaspune.org/peg/2013-02-21-09-18-33/item/95.html and b) The Enron Controversy: Techno-Economic Analysis and Policy Implications. http://www.prayaspune.org/peg/publications/item/91-the-enron-controversy-techno-economic-analysis-and-policy-implications.html

⁸ The Kanungo Committee Report includes an annexure on the exit of the AES. It provides many details and makes a startling statement that the AES had taken over the DISCOM CESCO hoping that its share in the thermal generation company, the Odisha Power Generation Corporation (OPGC), would be increased from 49 to 51%. When this increase did not materialise, the AES began losing interest in CESCO.

⁹ Those interested in a study of Appellate Tribunal can see the Prayas 2018 report. Available at: http://prayaspune.org/peg/publications/item/393-amicus-populi-a-public-interest-review-of-the-appellate-tribunal-for-electricity.html

¹⁰ CERC 2014 Order in petition no 159/MP/2012, available at: http://www.cercind.gov.in/2014/orders/SO159.pdf

¹¹ Supreme Court of India. (2017). Judgement in Civil Appeal Nos.5399-5400 of 2016 regarding the compensatory tariff matters.

¹² MoP Hydro power policy 2008. Government of India. Available at: https://powermin.nic.in/sites/default/files/uploads/new_hydro_policy.pdf

¹³ 2013 Report of the Comptroller and Auditor General of India on Public Sector Undertakings, 1 of 2013 Government of Uttar Pradesh. New Delhi: Comptroller and Auditor General of India.

¹⁴ Tariff Policy 2016. Available at: http://powermin.nic.in/upload/pdf/Tariff_Policy-Resolution_Dated_28012016.pdf

¹⁵ CEA 2018 report, Growth of the Indian Electricity Sector 1947-2018. New Delhi: Central Electricity Authority. Available at: http://cea.nic.in/reports/others/planning/pdm/growth_2018.pdf

¹⁶ Per-capita consumption is the figure arrived at by dividing the total electricity generation in a year by the mid-year population.

¹⁷ CEA 2018 Load Generation and Balance report. Available at: http://cea.nic.in/reports/annual/lgbr/lgbr-2018.pdf.

¹⁸ Details and status of Deendayal Upadhyaya Gram Jyoti Yojana (DDUGJY), upto village level are available at http://ddugjy.gov.in/portal, Office memorandum is available at: http://www.ddugjy.gov.in/portal/memo/DDUGJY-OM.pdf , Saubhagya status and details are available at: http://saubhagya.gov.in/

¹⁹ This is as per the data available at DDUGJY and SAUBHAGYA web portals. Office memorandum - Pradhan Mantri Sahaj Bijli Har Ghar Yojana (Saubhagya). Available at http://saubhagya.gov.in

²⁰ Details of Power For All Program, like plan documents for each state and minutes of review meetings are available at: http://powerforall.co.in/ . All consumers are expected to be provided 24 x 7 supply by 2019 or 2022 (depending on the state), except agriculture, which would get 8-10 hours of supply.

²¹ Those interested can read the brief 2018 Prayas article in the Economic and Political Weekly. Available at: http://prayaspune.org/peg/publications/item/399-rural-electrification-in-india-from-connections-for-all-to-power-for-all.html

²² All states except West Bengal and Odisha have signed up as of end 2018. Details of UDAY, including agreements and progress are available at: https://uday.gov.in/home.php

²³ Those interested can read Prayas submission on the draft E Act amendment. Available at: http://prayaspune.org/peg/publications/item/396-comments-and-suggestions-on-the-proposed-amendment-of-the-electricity-act-2018.html

²⁴ CAG Performance Audit of Allocation of Coal Blocks and Augmentation of Coal Production (Ministry of Coal), August 2012.

²⁵ Supreme Court of India. (2014). Judgement regarding the captive coal blocks de-allocation - Part 1 - Writ Petition (CRL.) No.120 of 2012.

10 : Understanding and planning for the energy transition

In the last Chapter we looked at the power sector reforms. While changes in the sector are continuing, there are some disruptive changes expected in the sector, which require a fundamental re-thinking on the future nature of the sector and a transition to a different way of operation and planning. This transition in the sector are driven by technology and economic changes. Unless guided by conscious policy decisions, these changes will unfold chaotically, leaving the electricity sector and especially, the distribution companies, stranded with excess capacity and huge losses. Such a fallout will impact the small and rural consumers with serious implications for state level politics. This chapter outlines the contours of the transition to explore how the transition can be fair and just.

The traditional electricity grid is a network wherein electricity flows from a few centralised, large electricity generators - mostly powered by coal and large hydro - over long distances through high voltage transmission lines to crores of consumers. Today, the electricity sector is at a crossroads. The rising cost of supply due to the procurement of high cost, baseload capacity, among other factors, and the emergence of competitive, renewable supply options are some of the trends impacting the sector. One major impact is the increasing sales migration which in turn results in a loss of cross-subsidy which is critical to the survival of the DISCOM’s existing business model. At the same time, the age-old challenges of high transmission and distribution losses, poor quality of supply and service, and increasing financial losses persist. In this context, this chapter discusses the trends that are impacting the sector and its political economy, and their implications going forward.

10.1 Changes underway and expected in the long run

The Indian electricity sector is undergoing major transformations due to concerted policy initiatives in India and global changes in power sector technologies and their economics. Some of the important ongoing and expected changes are noted in the next sections.

10.1.1 Universal household electrification

There has been significant progress in rural electrification, especially in the last decade (2008-2018). From a household electrification rate of 67% in 2011, we are now at 99.9% (as of January, 2019) and close to reaching the long awaited goal of universal electrification. Figure 10.1 shows the progress in village and rural household electrification. However, for many who are connected to the grid, supply is erratic and of poor quality - which are persistent challenges especially in areas where large numbers of houses have been newly electrified.

Figure 10.1: Rural electrification over the years

Source: Census data and Saubhagya portal

10.1.2 Competitiveness of alternative supply options and increasing sales migration

As discussed in Chapter 7, the electricity distribution companies (DISCOMs) in India have a cross-subsidy based tariff structure. Thus, some consumers including industries and commercial establishments pay a much higher tariff than small consumers such as residential and agricultural consumers. Under this model, it is very important that DISCOMs supply an adequate number of high paying, cross-subsidising consumers, otherwise tariffs for small consumers will need to be increased or the government will need to provide a much higher subsidy. While the overall demand was on the rise and DISCOMs were the only suppliers of electricity, this model largely worked. However, factors such as the rising cost of power procurement (including the cost of surplus generation capacity), high levels of losses and the increasing cost of distribution wires are leading to an increase in the average cost of supply of DISCOMs, thus making it difficult for them to continue with the cross-subsidy model.

On average, the cost of supplying one unit (1 kWh) of electricity was about Rs 7/unit in 2015-16. This has been steadily increasing at an average rate of about 6% per year for the past 3-5 years. Even assuming a modest increase of 4% per annum, the actual Average Cost of Supply (ACOS) for a typical DISCOM will be about Rs 8.5/unit in the next 3-5 years across states. Hence a ‘subsidising’ industrial or commercial consumer under the current DISCOM revenue model would pay a much higher tariff than the current rate, thereby compelling such big consumers to explore lower cost options. This makes alternative, low cost, non-DISCOM supply options (especially solar and wind) economically attractive for such consumers at least to meet part of their demand and significantly reduce their dependence on the DISCOM.

Consumers can shift to supply options other than DISCOMs in the following ways: a) by switching to open access and receiving supply from other suppliers to meet some or all of their demand; b) by setting up their own captive power plants, and c) by opting for rooftop solar through net-metering. In some states such as Maharashtra, Gujarat and Rajasthan, consumers accounting for more than a fifth of the state’s large consumer (HT) sales have moved to open access, while in some other states, those accounting for a similar share of the total sales of DISCOMs have shifted to captive consumption.

Rooftop solar prices are already in the range of Rs 3.5-4.5/unit, which are much lower than the DISCOM tariffs for commercial and residential consumers using more than 200 units per month. Thus, rooftop solar generation can be another option for consumers who have the roof space for installing such systems to migrate part of their demand away from DISCOMs. As of 2018, for consumers accounting for more than half the sales of many DISCOMs, augmenting supply with rooftop solar is economically very attractive, even without any subsidy or incentive, and only subject to availability of required roof space. (See Figure 10.2, which shows the illustrative case for the Maharashtra state DISCOM.) With the rising cost of supply by DISCOMs and the falling cost of renewable energy and electricity storage, this trend will only accelerate.

As such, sales migration through these different routes is no longer merely an emerging trend, but a reality for most DISCOMs. It is increasing despite procedural hurdles and high open access charges levied by DISCOMS. Loss of these sales is resulting in a significant loss in cross-subsidising revenue to DISCOMs. In addition, open access, which presently is mostly short term (i.e. these consumers get supply from other sources only for some time during a day or a month), makes power procurement planning more challenging for the DISCOMs.

Figure 10.2: MSEDCL DISCOM sales which can cost-effectively move to rooftop solar

Source: Prayas (Energy Group) analysis based on MSEDCL and SECI data.

Another emerging trend is the possibility of multiple power supply companies in the same area. Since 2014, there have been proposals to amend the E Act to bring about ‘separation of carriage and content’, i.e. to allow one company to own the wires and allow all other companies access to the wires to supply electricity to consumers. However, there remain many challenges and ambiguities in these proposals, and they have been opposed by several states as well as trade unions. Thus, it is not clear whether these specific proposals will be implemented, but it seems certain that going forward, such separation is very likely to be operationalised either through explicit legal amendments or increase in open access across different segments of consumers. Please see Box 10.1 Carriage and content separation.

Box 10.1: Carriage and content separation

Components of the electricity business involving wires and networks for transmission and distribution are considered natural monopolies, primarily because their physical duplication is considered wasteful and, in many cases, is not feasible. Thus, consumers in a particular area would be served by one monopoly distribution company; indeed, this is still the norm in India. Under the existing framework of the E Act, the distribution business is viewed as including both the provision of wires as well as the supply of electricity to consumers. Thus, the distribution company maintains and operates the distribution wires system and is also responsible for procuring electricity and supplying it using those wires to consumers. DISCOMs today are distribution and supply companies.

A common method to introduce competition in electricity distribution is to separate the DISCOM as two businesses - first is the wires business (lines and substations - the ‘carriage’) and second is the supply business (power purchase and supply - the ‘content’). The wires business remains a monopoly business run by a separate company, and this wires company is mandated to provide guaranteed non-discriminatory access to the distribution network to all electricity suppliers (known as distribution open access) and consumers. The wires company’s wires then act as a carrier for all supply companies who can compete for consumers by offering lucrative supply tariffs and other services. Figure 10.3 shows the distribution business before and after carriage and content separation.

As mentioned above, presently, the distribution business includes both the distribution wires and supply. If two distribution companies hold a license to operate in the same area, the E Act expects them to establish their own distribution networks, i.e. duplicate networks in the same area. However, it is important to note that by allowing open access to a certain set of consumers, the E Act does bring about a partial separation of carriage and content, though it limits competition. Also, several electricity regulatory commissions, such as those of Maharashtra have begun asking their distribution companies to provide their aggregate revenue requirement separately for wires and supply.

10.1.3 Increasing share of renewable energy

The global policy push coupled with the emphasis on R&D and greater scales of manufacturing and deployment have resulted in drastic reductions in the final cost of cleaner forms of energy production and use. Some of these price reductions, especially in the case of solar photovoltaics (PV) modules (94% during 2008-18), onshore wind turbines (37% during 2008-18) and lithium-ion batteries (85% during 2010-18) are quite remarkable. In India, wind and solar PV prices too have dropped rapidly and are presently available at a fixed levelised price of Rs 2.5-3/unit for a 25-year contract thereby reducing price volatility and risks. Globally, there are examples of even lower solar PV and wind prices as compared to India. There are existing bids of 2-2.5 cents/unit for solar (i.e., Rs 1.5-2/unit). Note that these prices of wind and solar power only reflect their direct generation costs, and do not value their other benefits in terms of minimal environmental externalities, enhanced energy security, modularity, low gestation periods, and low price volatility. Wind prices are even lower in some regions given their better wind resources.

These costs are expected to reduce even further in the coming years. This underscores the price - competitiveness of renewable energy. Therefore, generation prices are not going to be a hurdle for increased adoption of renewable energy in India. The CEA is projecting a renewable energy share in generation of 21% by 2022 if we meet the 175 GW target. This share is very likely to grow exponentially in later years. The drastically falling prices of wind and solar power and ever-increasing capacity have compelled even sceptics to acknowledge that renewable energy will play a major role in the future. However, there remain questions about how soon and smoothly this shift can happen, given the specific technical and regulatory challenges expected with very large shares of renewables.

Figure 10.3 : Carriage and content separation in electricity

Source: Prayas (Energy Group)

10.1.4 Coal based electricity losing its competitive edge

In a sharp contrast to renewables, the total price of generation from new coal plants (commissioned since 2012) has risen to Rs 4-5/unit, which is a paradigm shift from a decade ago when the price of renewables was significantly higher than that of coal-based electricity. Additionally, the price of coal-based electricity is not fixed for the life of the project and varies according to the price of coal, which has been historically rising. Based on the distance from the mine, a quarter to almost half of the landed cost of coal is generally attributable to transport, the price of which has also been rising sharply.

Apart from this, fixed costs of the newly commissioned capacity have been very high, largely on account of delays in commissioning projects. These costs are expected to rise further on account of stricter environmental regulations which the government has proposed for thermal power plants from December 2017¹. According to some estimates, implementing these regulations could add Rs 0.20 / unit to Rs 0.50 / unit to the costs of coal-fired power. This will make coal-based electricity even less attractive in comparison to emerging alternatives even without considering the possible additional cost of carbon in the long run. The generation cost of new renewable energy (especially wind and solar PV) will be lower than the average total tariff of existing and new thermal generation. This is likely to accelerate the shift away from coal, suggesting that the medium to long term outlook for coal demand may not be as bright as previously thought.

10.1.5 Electric storage

Energy storage is a unique asset, that can act as a load as well as a supply option. Similar to solar and wind, a continued price reduction is expected in li-ion battery packs as well. Its capital cost projections range from $ 75/kWh by 2030 (60% reduction from 2018) and $ 39/kWh by 2040 (77% reduction from 2018). This also translates to a 96% reduction in li-ion battery pack prices in the period 2010-40, similar to solar PV price reductions. In terms of levelised cost of storage in 2017 rupees, this would translate to roughly Rs 5/unit by 2020 going down to Rs 2-2.5/unit by 2030-40. This does not include the cost of energy for charging the battery.

Additionally, storage is very modular and can provide a variety of grid services simultaneously. Increasingly, it would be possible to store electricity at various scales and for a wide range of applications with increasing ease and affordability. Such considerations have resulted in the formulation of a draft National Energy Storage Mission in 2018 which will boost the adoption of storage technologies across the energy spectrum.

10.1.6 Electrification of transport

The transport sector is a major consumer of energy in the country. Since its predominant energy source is petroleum based, this sector is also responsible in a big way for the country’s energy import dependence, with India importing about 80% of its petroleum requirement. The transport sector also contributes significantly to vehicular air pollution. However, in the future, developments including the fall in prices of batteries, their improved performance, the growing awareness about air quality and its health impacts, and the ever growing petroleum import bill are expected to drive the electrification of the transport sector. According to one estimate, the share of the global sales of Electric Vehicles (EVs) in total vehicle sales would rise to over 50% by 2040 from its current 2% share. Adoption of electric buses is expected to be much faster.²

For India, a National Electric Mobility Mission Plan (NEMMP) was introduced in 2013 and up-scaled in 2015. More ambitious statements have been made about selling only electric vehicles by 2030 in India. These have been complimented by other research and regulatory studies, state level efforts and bulk procurement initiatives to accelerate the adoption of electric vehicles. Similarly, complete electrification of railways is being planned in the medium term.³ In addition, other initiatives will impact the future of the transportation sector. The smart city mission is expected to give a fillip to public transport, particularly metro rail systems. If MaaS (Mobility as a Service) is appropriately encouraged to dis-incentivise private transport, it has the potential to provide cheaper, more accessible and better-quality mobility. According to one estimate, the shift to 100% electric vehicle sales by 2030 would only add a marginal 3.3% in terms of annual electricity demand and 5.7% in terms of higher peak load.⁴ However, the nature and profile of battery charging can, if not handled properly, add greater stress especially on the local distribution system with high concentration of EVs.

10.1.7 Better energy planning for the environment and economy

The last decade has witnessed a massive growth in coal based thermal power capacity in the country. Most of these new plants are built by the private sector. Land acquisition as well as use of other resources for such projects has been fraught with intense local conflicts and litigation. Further, many of the installed and operational power plants are facing severe water and/or fuel shortages. In addition to coal based projects, ambitious targets have been set for hydropower capacity addition and opening up of new coalmines, all of which is only likely to worsen ongoing resource conflicts. These tensions have also resulted in changes such as the establishment of the National Green Tribunal of India, a specialised body to handle environmental disputes, the mandating of improved emission norms in 2015, and the recent directions from the government for safeguarding the health of those who live near or work at a thermal power plant, among other environmental issues. Going forward, these tensions are likely to become more intense as more energy projects compete for limited resources.

In addition to local resource conflicts and air and water pollution, the ever growing threat of global warming induced climate change as well as the need to achieve energy security have been key drivers for global clean energy policy. The International Panel on Climate Change (IPCC)’s special report on ‘Global Warming of 1.5 deg C’ published in 2018 underscores the enormity of the global warming challenge before humanity. Essentially, to limit temperature rise to 1.5 deg C, ‘global net anthropogenic CO2 emissions must decline by about 45% from 2010 levels by 2030, reaching net zero around 2050’. This implies a deep reduction in emissions and a rapid and paradigmatic shift in the global energy system. In spite of very low per capita emissions, India is the 3rd largest Green House Gases (GHG) emitter in absolute terms. Energy use contributed 83% of India’s GHG emissions in 2013, with this share increasing over time. Thus, shifting to a less carbon-intensive energy mix is central to India’s effort towards climate change mitigation. Under its Nationally Determined Contribution (NDC) to the 2015 Paris Agreement, India’s 2030 commitments are to reduce the emissions intensity of its Gross Domestic Product (GDP) by 33% to 35% compared to 2005 levels. The NDC also included a pledge to achieve about 40% cumulative installed electricity capacity from non-fossil-fuel based sources as compared to a share of about 35% by March 2018.

While international negotiations and associated processes have played a role in focusing attention on climate change, specific actions in the energy sector have more frequently been driven by domestic concerns and motivations such as energy security, the macro economy, energy poverty, local environmental pollution, poor financial health of electricity distribution utilities and rapidly changing techno-economics of renewable energy sources.

10.1.8 Non climate considerations for energy policy

India has a very high extent of geological coal resources (~315 billion tonnes), but the actual extractable coal reserves may be significantly lower and quite limited. In addition, domestic coal production (around 680 million tonnes in 2017-18) has not been able to meet demand, resulting in increasing imports. In 2017-18, the country imported 160 million tonnes of thermal coal (used for power production), while the total coal import bill (including coking coal) was about Rs 1,40,000 crore or $ 20 billion.⁵

The share of large hydropower has also been reducing given the increasingly limited and difficult sites available. This is not even considering the large social and environmental impacts including those on account of the submergence of large tracts of land and forests, and uncertainty regarding the final costs and generation.

Similarly, India is extremely dependent on imported crude oil, natural gas and other petroleum products, with its import dependency as high as 80%. While this not only has implications for energy security and foreign policy, it has a very direct impact on the macro-economic situation in terms of deepening the Current Account Deficit (CAD) and the rupee-dollar exchange rate.

Finally, India has the dubious distinction of being home to some of the most polluted cities and towns in terms of air quality, which is partly a result of coal, biomass and petroleum burning for various energy services. Many of these considerations are already being reflected in Indian policy formulation as is seen from some of the examples noted above.

10.2 The changing nature of the electricity grid

As mentioned earlier, on account of the various technological, economic, end use and business model changes, the electricity grid is quickly evolving into a more complex network. These trends have the potential to effect a paradigm change in the electricity sector in the long run, as we will see in the next sections.

10.2.1 Large number of new entities, need for higher flexibility

Adoption of newer technologies such as decentralised renewable energy systems, on-site generation, electric storage and electric vehicles will result in an increased number of entities connected to the grid. As of December 2018, nearly 3.4 GW of rooftop solar projects have been commissioned and significant capacity is in the pipeline. Depending on the average project size, the 40 GW rooftop solar target by 2022 would entail anywhere between 10 to 20 lakh individual projects. This is orders of magnitude higher than the roughly 1250 existing, large scale, conventional generation units in India. Similarly, the number of private and public charging points for electric vehicles is also expected to increase over time. Smart electric chargers will enable Vehicle-to-Grid (V2G) services being offered. This will essentially allow the EV batteries to trade some of their electricity back into the grid in times of stress.

As a result, many consumers will not just be consuming electricity, but will also produce and trade it, making them ‘prosumers’. This will also lead to greater instances of electricity flowing from the consumer end back into the grid, unlike the existing one-way flow from large generators to consumers. These entities are also expected to have characteristics different from traditional consumers and producers of electricity, and hence the grid is likely to need more flexible supply and demand to maintain reliability. Demand flexibility, enabled by sophisticated information and communication technologies allows loads to constantly respond to the system requirements. This helps in managing the load and maintaining grid balance. This would be necessary in a system that has high renewable energy generation that is variable and intermittent in nature or if there is significant diurnal variation in load. It can also help lower costs by responding to market price signals. These factors are likely to make both demand and supply estimation and planning more complicated. Moreover, in a network with such a large number of entities (consumers, generators, traders) connected to low and medium voltage level, the distribution grid it is expected to play an increasingly important role in the power system of tomorrow. Please see Box 10.2 Smart grid, smart meters.

Box 10.2: Smart grid, smart meters

Ongoing developments in the form of increasing sophistication and ever-reducing costs of information and communication technologies (ICT) enable precise and granular monitoring and sharing of information in close to real-time. This is a large part of the emerging trend of smart grids and smart meters. According to the Smart Grid Handbook⁶ for regulators and policy makers, ‘Smart grid is an electricity grid with communication, automation and IT systems that enable real time monitoring and control of bi-directional power flows and information flows from points of generation to points of consumption at the appliances level.’ Similarly, smart meters essentially allow for recording of electricity consumption and other power quality metrics at a more detailed level, and further have the capability of two-way communication with the DISCOM. These technologies coupled with emerging techniques of data processing allow for increasingly complex operations for more sustainable, reliable and lower cost power system management.

A clear example of a future possibility in such a system is smart charging for Electric Vehicles (EVs). The smart EV charger would have the ability to sense the grid conditions and charge in a manner which does not add stress to the system (for example, not charging during peak load conditions and making use of low electricity prices during certain times of the day for charging). Smart EV charging can significantly influence the potential impact of EVs on the grid. Moving charging to a certain time of the day with cheap renewables can not only reduce overall system costs but also help with RE grid integration (reduce curtailment) and reduce emissions.

Curtailment is a reduction in the generator’s power output from what it could have produced otherwise. This is typically done on the orders of the system operator (load dispatch centre) to ensure system balance of supply and demand. This is relevant for weather dependent renewable energy sources like wind and solar since such curtailed power is essentially lost unless it can be stored in some form. This is different from backing down of conventional thermal power plants which can save on fuel cost when asked to back down.

Further, consumers/prosumers, enabled through smart grids and meters, may become equipped to provide generation and demand flexibility to the grid as needed. This could be in the form of shifting load to off-peak hours using the incentives and penalties of time-of-day tariffs, demand response and distributed supply from rooftop solar PV/batteries, etc. Demand response allows consumers to respond to the DISCOMs need to reliably balance supply and demand, especially at times of peak load. This is done by consumers voluntarily by shifting their load to off-peak times for which they receive some form of compensation. In this regard, smart meters can allow pricing of electricity which is more reflective of its time and locational value.

While the emerging paradigm of smart grid allows for various new and exciting opportunities, it is important to keep in mind the several possibilities in the existing system, which can and should be leveraged to increase the reliability and lower system costs without waiting for the smart grid to come to fruition.

Additionally, it needs to be noted that there are significant challenges in large scale use of such ‘smart’ technologies. These include systems integration, connectivity, proper maintenance and monitoring, effective use of data for improving actual operations and efficiency.

10.2.2 Weather dependency and reliable integration of renewables

A basic characteristic of renewable energy sources (especially wind and solar) is that they are dependent on weather conditions, making their generation output variable in nature. Wind and solar power output varies on all time scales from seconds to years. For example, solar power output is dependent on the irradiation and temperature of the location which vary on an hourly, daily, seasonal and annual basis. Generally, solar power output peaks at noon each day, while wind power peaks during the monsoon months in India. Secondly, depending on the extent of forecasting accuracy, there is a degree of uncertainty in this variable generation. Due to the diurnal and seasonal variations (more pronounced in the case of wind power given the Indian monsoon) in generation, its shorter time scale (minutes to hours) impacts on the grid are much higher than perceived impacts considering only the lower annual average values. For example, penetration of wind power in energy terms in Tamil Nadu in 30-35 % from June to September and 5-10% during other months. This inherent variability coupled with the uncertainty over forecasting accuracy makes matching supply to demand in real time more complex with the increasing share of renewables.

The increasing share of wind and solar power will create newer challenges for planning and operating the grid including the need for more system flexibility. These primarily arise, as explained above, due to variability in the supply and demand due to weather patterns on a diurnal and seasonal scale. Because of this variability, it is anticipated that the future grid dispatch practices will see a stronger integration of grid dispatch with weather forecasts. As a result of weather changes, a large portion of wind and solar based generation can become available or unavailable (over different time scales from minutes to hours), and the generation from the rest of the sources as well as demand will need to match this gap. Coal based plants that form the bulk of the non-renewable generation sources may not be able to change their generation quickly enough to absorb this variation. It is also likely to drive stronger cooperation between states since the sharing of flexible generation and load resources among states and coordinated scheduling are likely to enable greater low cost integration of renewables which would be a win-win situation for all participating states. Hence, going forward, various strategies which help in addressing the increasing variability and intermittency of the power system will be needed.

10.2.3 Changing nature of the grid

With all these trends, the nature of grid is changing. Today, most consumers get their entire electricity from one supplier. Their monthly energy bill is made up of two parts, a fixed charge which covers the fixed costs of the DISCOM, and an energy charge which covers the power purchase costs of the DISCOM. The fixed charge is levied on the consumer irrespective of whether one consumes any electricity. This is because there is a fixed cost involved in maintaining the generators, transmission and distribution lines in operating condition - ready to serve the consumer at any given moment. There are additional fixed costs in maintaining power quality and system reliability in terms of grid services like reserves of different types, backup generation, voltage regulation and black start. These essential services are practically never separately accounted for and charged as per consumer usage, especially when a sole supplier meets consumer needs. Energy charges could be solely based on the cost of power purchase by the DISCOM and amount of energy used by the consumer. The aim of the DISCOM is to recover the total cost of distribution and supply from the consumer, in the form of tariff. Tariff structure of most DISCOMs do not have fixed charges calculated so as to recover the full fixed costs. This leads to energy charges that are higher than what could be calculated based on just power purchase and energy use.

Low cost renewable generation coupled with storage, energy management and efficiency strategies could significantly undermine the traditional role of the grid which was to provide electricity to consumers by connecting few large generating sources to numerous consumers. In spite of generating or procuring your own electricity, consumers would continue to expect 24 X 7 reliable power supply throughout the year with the support of the grid. As a result, in the coming decades, we can expect a diversification in the role of the grid. Going forward, grid services are likely to become as critical as supply. Hence the grid could offer these various separate services apart from just providing electricity. These services could include:

Access to markets through grid interaction allowing for drawal or supply of power in times of deficit or surplus generation respectively.

Supply quality, reliability and back-up services especially in the case of open access and captive consumers procuring renewable electricity, which is variable in nature.

Optimal sizing/operation of the distributed energy systems with grid support, which ensures that these systems do not have to adjust output as per localised demand.

Two such examples of the changing role of the grid are already playing out in the Indian renewable energy sector. Nearly all states in India allow for energy banking and net-metering for renewable generators on account of the diurnal and seasonal nature of generation. The grid provides a service in terms of a large virtual battery wherein excess generation can be ‘banked’ and redeemed later when needed.

The transmission network also enables setting up of large off-site wind/solar power plants for self-consumption or sale to a third party (open access) by paying the appropriate charges for the use of the wires as transmission and wheeling charges. Wind/solar plants can generate only when it is windy or sunny, and their generation cannot be predicted with certainty. However, consumers would like to use the ‘grid service’ of getting power on demand despite having their dedicated wind or solar farms to offset their energy use from the DISCOM.

The emerging trend of using the grid for the non-energy services it provides, namely energy banking, supply reliability and transmitting power from remote locations, is observed in practice in many instances.

10.2.4 Issues of rural and small consumers

As noted before, the traditional model of managing the distribution sector in India is not sustainable. Crucially, it is not just DISCOMs that will be impacted due to the changes in the sector. As electrification accelerates and crores of newly electrified households join the grid, the fate of all small, rural, and agricultural consumers is also at stake. In the transition process, the most important issue is that of quality and reliability of supply to these consumers, especially in an era where large consumers have the freedom of choice in terms of their energy supplier.

Figure 10.4: Issues with quality of supply

Source: Electricity Supply Monitoring Initiative (ESMI) http://www.watchyourpower.org

Figure 10.4 shows the extent of the quality of supply issue and covers data from 135 locations across seven states in India. The average duration of supply is 18 hours/day, which includes only 4.5 hours during the crucial evening period (between 5 and 11 pm). Nearly two-thirds of households faced outages of more than 15 hours a month while three-fourths faced more than 30 interruptions a month, each longer than 15 minutes. As the number of consumers grow, issues in metering and billing are also likely to exacerbate. For effectively managing this demand from the newly electrified households and the other small and rural consumers, and providing them a reasonably good and reliable supply, the DISCOM will need to be in good health both financially and in terms of its operational capacity.

10.2.5 Growing complexity and importance of sectoral planning

Chapter 8 and 9 noted the various planning failures in the Indian electricity sector over the last 3 decades. Given the characteristics of the electricity sector such as its capital intensive nature, long gestation periods for conventional generation (thermal, nuclear and large hydro) and transmission projects, and their (mostly adverse) impact on significant ‘commons’ resources such as water, air and community land, planning is a function that cannot be wished away. However, planning as currently practiced in the electricity sector is mostly based on extrapolation of historic trends. It is also mostly undertaken with a department-wise approach (like coal, railways, agriculture, power and irrigation), rather than in a comprehensive manner. There is limited rigour in critically evaluating and prioritising needs, anticipating changes and risks, and preparing for them.

Figure 10.5: Changes and challenges in distribution sector

Source: Prayas (Energy Group)

Considering the impending transition, in order to effectively guide the electricity sector, the nature of planning needs to undergo a significant change. More specifically, it needs to become more comprehensive and multi-sectoral - that is, it should consider the interlinkages and interactions with all related sectors such as fuels, the environment, financial institutions, railways and state governments. Failure in doing so can lead to serious long term implications in terms of resource-lock-in and path dependency.

The emerging trends such as the increasing share of renewables, the changing characteristics of entities connected to the grid, and the changing utility business models will surely make sectoral planning more complex. At the same time, role of planning is all the more important today as compared to the past. One of the main reasons is the uncertainty in demand assessment, especially over the medium to long term. This is on account of the large number of new consumers, prosumers, EVs, battery systems, weather dependent renewables, Time of Day (ToD) pricing and non-sectoral variables like urbanisation and rising incomes which will not only influence the total demand but more crucially its temporal (diurnal/seasonal) and spatial nature. This will have far reaching implications for generation, transmission and distribution network planning and operation. Figure 10.5 is a representation of the multiple changes affecting the distribution sector. Distribution sector is represented as a hot air balloon, carrying many consumers in its journey. It faces multiple challenges like increasing renewable generation, deserting big consumers and theft - all of which rock or rupture the balloon.

This unfolding transition has the potential to make the existing challenges worse and even create newer ones, but it also brings in new opportunities. These could include enhanced energy security while increasing the share of renewable energy and greater consumer choice, among others. Planning will have to be reimagined for an era of increasing uncertainty, risks and fast paced changes. In this context, an excerpt from a 1980 paper on risk management by W C Clark is very pertinent. According to him,

The most important lesson of both experience and analysis is that societies’ abilities to cope with the unknown depend on the flexibility of their institutions and individuals, and on their capacity to experiment freely with alternative forms of adaptation to the risks which threaten them. (Emphasis added.)

Thus, it is our collective response through policy, regulation and pro-active preparation which will determine whether reliable, affordable and sustainable electricity can be provided to all.

10.3 Preparing for an uncertain future and shaping a just transition

The previous sections clearly explain the need for a transition in the electricity sector and its inevitability. While there is greater clarity on what to transition towards - a power system which provides reliable, affordable, universal and sustainable electricity supply along with consumer choice - many questions on how best to get there remain to be addressed. Some of the potential steps to prepare to deal with the transition are noted below.

10.3.1 Preparing for a ‘future’ electricity distribution sector

The existing business model of DISCOMs is based on the practices of revenue recovery through the ‘cost-plus’ method of determining tariffs, cross-subsidy based tariff design, and meeting demand largely through long term baseload contracts often on a cost-plus basis. The uncertainty in demand on account of competitiveness of competing supply options and loss in cross subsidy on account of sales migration is likely to have two serious implications for the DISCOM’s future:

The loss of cross-subsidising consumers would force DISCOMs to increase the tariff for small, rural, and agricultural consumers, which in turn would increase the need for direct revenue subsidy by state governments.

Planning for power purchase, which has always been a weak link in the DISCOM’s business model, is likely to become even riskier and more complex.

Both these factors, if not managed appropriately, can lead to severe financial stress, not just for the DISCOMs but also for the sector at large. With a large number of consumers opting for alternate supply options, the DISCOM will need to change from its existing supply function to being mainly a wires licensee.

The short-term nature of open access coupled with the variable nature of renewable energy sources would mean that grid services in the form of say, balancing and reliability services, would become increasingly important. It is very likely that such services would be provided by or through the local DISCOM. The likely future scenario for the DISCOM is shown in Figure 10.6. While the role of the DISCOM may change, a robust grid and economically viable distribution sector are critical to ensure reliable and sustainable supply. If the serious challenges facing the distribution sector are not squarely addressed, this may not be achievable and the poor and marginalised consumers would be the most affected.

Figure 10.6: Changing nature of the DISCOM

Source: Prayas (Energy Group)

One possible and dangerous outcome of this emerging scenario is the collapse of the DISCOM, which would be detrimental to meaningful access to electricity for small and rural consumers, and also highly undesirable for grid stability. It is therefore in the sector’s as well as society’s interest to ensure that DISCOMs manage a smooth transition to the future and are able to fulfil their new role competently and efficiently. The way to achieve these goals is to quickly usher in changes that will help the distribution sector to adapt and cope with the emerging trends.

Need for rapidly reorienting the existing cross-subsidy based approach

The loss of revenue from cross-subsidy due to high-paying consumers moving to other sources will make it difficult for the DISCOMs to provide supply to low-income households and agricultural consumers at lower tariffs. This would lead to increasing pressure on state budgets to provide higher subsidy for these consumers. To ensure that these consumers are not unduly affected from a tariff impact arising out of lack of a planned transition, it is important to move away from the cross-subsidy based tariff approach.

Additionally, reserving existing low-cost generation for subsidised consumers and shifting their load, such as say that of agricultural consumers, to solar power through solar feeder approach⁷, which is relatively cheaper, could be some of the alternatives to consider in this regard.

Essentially, this implies that to stay relevant the DISCOMs would need to develop new business models, as going forward, these small, rural and low-paying consumers are going to be their main constituency. For the rest of the consumers connected to the grid, the DISCOM would still need to continue to provide the wires network and fulfil other technical functions required to maintain grid stability. Considering this, sales migration should be planned for pro-actively rather than letting it happen in an ad hoc and market driven manner, and appropriate mechanisms to enable it should be put in place.

Future power procurement and planning

DISCOMs will need to undertake more realistic capacity addition planning while accounting for changing technologies, their costs and national commitments regarding non-fossil fuel capacity. So far power purchase planning has meant signing long term contracts for baseload, mostly coal based thermal power. However, this will not be as useful in the future given the uncertainties in both demand and supply. The need for additional capacity to meet peak load will increasingly be dictated by times of the day and seasons with a combination of high demand and low renewable energy generation. This would encourage renewable energy planning, which is valued not just for its lowest generation costs, but also for other attributes which are important for system operation and costs. These include its contribution to meeting peak load, namely its ‘capacity value’, since this will determine how much additional capacity would have to be built. It will also include the need for additional transmission infrastructure depending on its location.

Considering this, future power procurement will need to be done only after more rigorous and scientific analysis that considers demand patterns and variability/intermittency due to various supply options. Similarly, all new generation facilities would also have to play a dual role by not limiting themselves to energy provision, but by also facilitating more flexible operation and grid support through the provision of ancillary services. System operators use a set of tools collectively referred to as ‘ancillary services’ to ensure the reliability, stability and balance between generation and demand of the power system in the short term. Examples of these services are operating reserves and mechanisms to maintain frequency and voltage within normal levels.

Since most of the new capacity may be needed for peak and intermediate load, rather than to meet the baseload, different kinds of contracts such as those for short term and peaking supply, and purchase from exchanges will need to be explored and utilised. Such a power purchase planning exercise should be undertaken in a transparent manner through due public process. This would ensure that the new capacity addition, especially for the long term baseload capacity, is considered only after all the existing and under construction capacity at the national level is utilised to the fullest extent.

Both the above aspects require improving the efficiency and accountability of the DISCOMs by addressing their governance and capacity deficits.

10.3.2 Need for new consumer tariff models

As mentioned before the current tariff regime in India is made up of a fixed charge as well as an energy charge per unit. Fixed charges generally form a much lower part of the entire consumer bill in comparison to the energy charges resulting in the utility recovering a part of their fixed costs from the energy charges. However, a scenario with increased open access and on-site generation (like rooftop solar) with storage could mean that consumers may opt out of or significantly reduce buying electricity from the DISCOM. This could lead to significant impacts on the DISCOM revenue as these consumers begin to utilise the grid more for their non-energy services despite paying the relatively lower fixed charges. This has a potential to impact the DISCOM’s ability to provide essential and affordable electricity services to the poor. With this in mind, it is necessary to develop newer tariff models for consumers who are only partially dependent on the DISCOM. Such models should be distinct from those meant for small and rural consumers, should capture the dynamic needs of large consumers who are procuring supply from multiple sources, and should focus on grid services rather than just the sale of electricity.

10.3.3 Need to monitor and improve quality of supply for small consumers

With increasing loss of cross-subsiding sales, the already difficult financial situation of DISCOMs is likely to become worse. At the same time, a large number of households are getting electrified and joining the grid. These consumers would typically consume somewhere between 50-100 units per month and hence would fall in the lower tariff slabs. As such, the DISCOMs are not likely to make a lot of money by selling power to them, and hence if finances get stretched, these consumers will suffer the most on account of load shedding and poor maintenance of the rural distribution network.

Therefore, in order to sustain the gains from the recent electrification drives and to ensure reliable and affordable supply, there is an urgent need to put robust systems in place for monitoring of supply quality especially for small consumers. The current regulatory processes do not place much emphasis on this aspect. The central government has set up a portal for monitoring the connection drive, but once connections are provided, systems will need to be set up to track actual supply hours. In addition to hours of supply, the grievance redressal mechanism will also need to be significantly overhauled.

10.3.4 Greater emphasis on data and knowledge

The rapid changes in the sector coupled with the various uncertainties means that it is extremely important to comprehensively track, monitor and collect important data. This has to be planned for pro-actively and will allow for a clearer understanding of the trends and appropriate course correction. For example, the increasing number of entities connected to the grid, their changing characteristics and implications for the load shapes needs to be captured effectively. Presently we have a very limited understanding of various high power appliance usage patterns, for example ACs and EVs. Given this increasing complexity, it is all the more important to allocate more resources towards building sophisticated power system models and running various scenarios to enable better planning and cost-effective capacity addition and operation of the power system.

The very large number of small generation projects (mainly in the form of rooftop solar) would result in a high number of contracts and associated transaction costs for the DISCOMs. This would need to be smartly addressed through simpler contracts and greater emphasis on digitisation of records and transactions to avoid such processes from becoming unwieldy, and to facilitate effective consumer interaction.

10.3.5 Energy efficiency uptake

Energy efficiency solutions not only reduce energy consumption and greenhouse gas emissions, but also in most cases lower life-cycle costs, though upfront costs may be higher. India has a mixed record of promoting energy efficiency. The Unnat Jyoti by Affordable LEDs for All (UJALA) programme for promoting efficiency in lighting involved bulk procurement of Light Emitting Diodes (LEDs) without any subsidies. It resulted in more than 31.5 crore LED bulbs being sold by November 2018. While this initiative created a large and sustainable market for LED bulbs at reduced prices, in many geographies low-income households and small commercial establishments continue to buy incandescent bulbs due to their lower upfront costs, thus raising questions on how the penetration of such programmes can be increased.

A similar mixed experience is seen in the BEE’s Standards and Labelling (S&L) programme. While standards for 5-star frost-free refrigerators are comparable with international benchmarks, there is significant room for improvement in the standards for 1-star frost-free refrigerators and air-conditioners. This is especially relevant since many studies predict a huge rise in electricity demand for cooling in India as the penetration of air conditioners increases.

The efficiency programme for industry, the Perform-Achieve-Trade (PAT) scheme, is also into its second phase. Under this programme, a set of ‘designated consumers’ are given targets to reduce specific energy consumption. However, it has been suggested that these targets are still quite weak. For example, the PAT standards for some performance parameters of thermal generation and electricity DISCOMs are weaker than those defined by regulators and government programmes such as the Ujwal DISCOM Assurance Yojana (UDAY).

Thus, the scale and pace of adoption of energy efficiency measures is still an open question and will depend critically upon proper design and implementation of these programmes. This will have significant implications on the scale and nature of electricity demand, associated generation supply and required system flexibility.

10.3.6 Grid integration of renewable energy

With low generation costs, the major challenge today for the adoption of renewable energy sources is reliable and cost-effective grid integration, which requires advanced techniques such as modelling to understand the additional stress and complexity on system planning and operations. Being a variable and intermittent source of energy, procuring wind and solar energy entails higher system-integration costs. This could be for balancing the intermittency or for building additional capacity to be run at times when wind and solar generation is low. This needs to be factored in for comparing the price of renewable energy with other sources and its value to the system. As the penetration of renewable energy - which typically has ‘must-run’ status due to near zero marginal cost - increases, the ‘peakiness’ of the net load increases, which means that the rest of the generation sources must have greater flexibility to respond to changes in load. Also, as more and more consumers are likely to opt for generation from these sources for meeting their own consumption, they will also impose the variability and intermittency of these generation sources on the larger grid and hence on other consumers.

Therefore, there is a need to develop a framework to equitably distribute the additional costs of grid integration of renewable energy among all the concerned stakeholders. Another crucial variable that would determine the future trajectory of renewables is the development of technology and the regulatory regime around energy storage, as this can greatly help eliminate or reduce the variability and intermittency associated with renewables. While the growth of renewables thus far has been nurtured through policy-regulatory instruments such as preferential tariffs and minimum purchase obligations, they will increasingly have to confront mainstream sectoral challenges. Essentially, going ahead, entities procuring renewables should account for their impacts on the system and not just go by RE targets.

10.3.7 Rethinking the institutional framework for planning and operation

As highlighted in Chapter 8 and 9, the lack of an integrated approach to planning of the sector has been a major challenge. This continues to be a trend even with the sector undergoing rapid changes. For example, there is an aggressive push for adding 175 GW of renewable capacity by 2022, but there are also ambitious plans for adding coal based capacity and to increase coal production. This is in spite of the sluggish growth in demand. Similarly, there are ambitious plans to move the transport sector towards alternative fuels such as electricity, along with an equally ambitious plan to augment the country’s petroleum refinery capacity.

Thus, there seems to be little clarity in terms of how the various policy goals are supposed to converge or how best the underlying objectives can be achieved. This is largely so because of a lack of institutional capacity that is required for sound planning and effective implementation. Unfortunately, our institutions are often more engaged in dealing with issues of a more immediate nature, and hence they lack the bandwidth and capacity needed to both envision and engage in long term planning for the sector. Further, there is very little focus on monitoring implementation, learning from experience and making mid-course corrections.

In the context of the upcoming changes, this is likely to be a very crucial weakness and can have long-term adverse implications. Therefore, it is important to rethink the institutional framework and to focus attention on capacity development. This should allow for more holistic yet flexible planning for the sector by taking into account developments across different sectors. Planning should also create processes that can account for state and local level changes and empower decision making and operations at the local level to some extent. For example, to better plan and manage generation by rooftop PV and EV charging/discharging at a local level, decision making must be delegated to circle/district level engineers, since they are in a better position to monitor rooftop PV penetration, EV charging patterns, wear and tear of equipment, generation and use, and changes needed in distribution network safety settings and equipment. This would entail greater emphasis on distribution system planning which takes into consideration these upcoming and rapid changes. Similarly, the role of the ERCs would also need to evolve accordingly. They would need to give much greater attention to their monitoring role in terms of market and supply quality monitoring. As noted in section 10.2.5, they would need to be more nimble, flexible, and open to newer ideas and experiments for tariff design, business models, power procurement strategies to ensure a smoother transition.

India’s electricity grid infrastructure and services can be drastically different across states and have their own set of challenges in planning and operation. While policy makers must actively and quickly try and bridge the gap between such states, it is important that they take into account differing starting points while planning for the electricity grid, and that they are sensitive to state realities. One-size fits all solutions are unlikely to work across India, especially considering the changing role and character of the grid along with its increasing complexity and local variations.

10.3.8 Reducing the relative significance of coal and petroleum in the long run

Importance of a just energy transition

Since the energy transition would invariably involve some winners and losers, some tricky political questions would also have to be addressed. The ‘losers’ are likely to be the traditional energy sectors of coal and thermal power. Since these sectors, particularly the coal sector, are concentrated in the eastern and relatively poorer part of the country, the political impact of losses in jobs and revenue (from different sources like taxes, fees, levies and royalties) due to a decline in the role of coal are likely to be significant.

The coal and thermal power sectors are also important because they provide employment, albeit hazardous, to many people. Coal India Limited (CIL) presently employs close to 3 lakh people apart from 1.25 lakh contractual workers. Apart from this, Singareni Collieries Company Limited (SCCL) employs nearly 50 thousand people. The eastern states are also less renewable resource rich, and therefore less likely to benefit from the ‘new’ energy sector which is surely going to offer significant new employment opportunities, especially in the growing wind and solar PV sectors. These jobs are more likely to be in Engineering Procurement and Construction (EPC) and Operation and Maintenance (O&M), and less so in manufacturing which is significantly automated. The policy makers/unions need to pro-actively plan for a more just transition which explores options like early retirement, re-skilling and ecological restoration.

A recent but small example of such an approach was seen in Spain, where in the government and unions agreed to shut down most coal mines after a financial package of € 250 m was greed upon to be invested in the region over a ten-year period. This would cover early retirement for miners over 48 years of age, environmental restoration of mines and reskilling for new green industries.⁸

Coal and petroleum taxation

There are presently a large number of royalties and taxes levied on coal. These include royalty (14%), District Mineral Fund (30% of royalty), Goods and Services Tax (GST) (5%), and the GST compensation cess (formerly the clean energy/environment cess of Rs 400/tonne). Apart from these, there are many other (smaller) taxes. Our broad estimate for the total tax collected from coal produced in the country in 2016-17 (708 Million Tonnes), assuming the base price of coal to be Rs 1200/tonne (weighted average of CIL notified price by grade), is roughly 66,000 crore rupees. This is equivalent to the total annual electricity revenue subsidies provided by state governments. The loss of this tax revenue, especially in the poorer coal bearing areas, will have significant implications for the local economy and will affect investment and economic development. States most likely to be affected are Chhattisgarh, Jharkhand, Madhya Pradesh, Odisha, and Telangana.

A shift in the transport sector towards greater electrification and MaaS (Mobility as a Service) is likely to lead to fundamental shifts in the petroleum and automobile industry and ancillary services, with repercussions for the economy and employment. Electrification of transport will significantly affect the central/state tax revenues which are strongly dependent on petroleum. Presently, 30% of total Indian tax revenue comes from the petroleum sector, with a contribution of 5.5 lakh crore in 2017-18. This will need broader economic reforms that take into account the changing nature of the energy sector.

Railways dependence on coal freight

Revenue from coal freight is crucial for the financial health of the railways. Presently 30% of its revenue is from coal freight, in spite of the total coal tonne-kms slightly reducing over the last few years. Increased revenue is mainly due to the doubling of coal freight rates in the same time period. Railways provides significant support for various types of passenger movement including labour movement across the country. Hence, politically sensitive railway passenger fares will come under pressure as the Indian Railways’ revenue from coal tapers off in the long run, thereby reducing the ability of freight to subsidise passenger traffic.

Flexible coal power for grid reliability

With the increasing share of renewable energy in the electricity generation mix, the Plant Load Factors (PLFs) for coal power plants, which are already at a low of 55-60% and declining, will further reduce over time. This will potentially drive coal power plants to become more flexible and possibly operate in a two-cycle daily shift, essentially before and after low cost solar power is available to the system. Therefore, the value of coal generation to meet peak load and operate flexibly will enhance over time. Such generation capacity, if it is needed mainly for reliability, flexibility and seasonal needs, will need appropriate cost recovery mechanisms. The current tariff structure of coal based generation is based on an assumption of the need to run it as long term, baseload capacity. If this kind of pricing is continued in practice, in the long run, there is a high risk of creating further stressed assets. In the short term it is likely to result in excess baseload capacity.

Since India’s coal reserves are in thickly forested areas, their exploitation may also conflict with our Nationally Determined Contributions (towards reducing climate impacts) of increasing afforestation. While coal generation capacity addition is likely to continue in the short to medium term, it will certainly peak at some time and reduce thereafter. However, falling load factors means that the need for coal production may fall much faster than generation capacity. Again, coal utilisation is also certainly likely to increase in absolute terms in the short to medium term, though the long term outlook seems bleak. This has serious planning and governance implications for the coal sector, which is getting potentially ready for more reforms. Similarly, it raises questions on the need for opening new mines, the utilisation of existing mines, environmental restoration and coal imports. Perhaps more than other sectors of Indian energy, the ability of the coal and thermal power sectors to develop in an equitable, fair and optimal manner will have the greatest bearing on the future of India’s energy sector.

Environmental and social concerns

We as a country have a very poor track record in dealing with environmental issues and human displacement. Even when the coal-thermal sector was at its peak in terms of private sector interest and flow of investments, hardly any attention was paid towards compliance with basic environmental norms and safeguards. As the investments and interest in the sector begin to decline, there is a likelihood of even further neglect. Given the serious adverse impacts of coal mining and thermal generation on the local environment as well as people, these issues are likely to become much worse with the reducing role of thermal generation, and will need even greater attention from the government and civil society.

Thus, meeting the multiple objectives such as optimising investments, avoiding undesirable lock-ins, providing affordable and reliable power to all, providing employment, and protecting the local and global environment requires a great deal of deliberation and negotiation as well as a comprehensive and holistic regulatory and policy approach.

10.3.9 Implications for governance, politics and equity

Most of the energy sector is characterised by its investment heavy nature, long gestation, long life, technical complexity, and close linkages to other sectors such as the wider economy and environment. This makes effective governance of the energy sector crucial as well as challenging. Energy governance also involves political contestation as the different interests of various stakeholder groups need to be balanced. Electricity is a concurrent subject in the Indian constitution, which brings its own challenges related to state and centre relations. The traditional governance challenges including the structural institutional weaknesses, insufficient capacity, accountability, and transparency will get amplified with the changing nature of the energy sector, and particularly of the electricity sector.

In the context of the trends discussed so far, policy and regulation will have to deal with possible contract renegotiations, redesigning tariffs to make thermal plants run more flexibly, aspects of electric vehicles such as tariffs, safety and standards, and regulation of MaaS (Mobility as a Service), amongst other aspects. Appropriate value and incentives for flexibility (demand and supply) are key to the development of a low cost system with a high share of renewables. This will need new regulations and market instruments. The lack of a flexible grid would result in a grid relying on a high cost fossil fuel backup system.

The central and state governments in India often have different priorities. The centre’s perspective is informed by macro-economic stability, economic growth and geo-strategic issues, while the states are driven more by local concerns and political realities including energy access and affordability, as well as local jobs and economies. A transition in the energy sector would bring these differences into sharper focus. For example, the centre may want to promote renewable energy more aggressively to reduce costs, energy imports and pollution and to meet international obligations. However, the ramifications at the state level may be different and will vary across states. For example, coal rich states may lose jobs and royalty revenue, while states with excessive renewable energy (such as Tamil Nadu) may either face grid instability or have to back down renewable energy if it cannot be dispatched and sold elsewhere.

India has to tread a very careful path by considering the multiple dimensions of the challenges, understanding the trade-offs and choosing the best possible option. This would require policy formulation which adopts a different frame of reference that includes such considerations, and a much more deliberative and inclusive process. Thus, India’s energy sector future is not only dependent on how it deals with the sectoral aspects discussed in previous sections but also on how it manages these tricky governance and political questions.

10.3.10 A larger question: How much energy do we need?

The ever growing environmental impacts of energy use, namely global warming induced climate change, local air and water pollution, as well as changes in land use are starkly evident for anyone to see. Secondly, the benefits of modern forms of energy use are highly inequitable due to the twin challenges of access and affordability. This brings up fundamental questions on how we should produce energy, price it and more importantly how much energy is needed in the first place. Please see Box 10.3 How much energy do we need?

Various emerging solutions in the form of energy efficiency, renewables, storage and electric vehicles are pointing to some form of technical solution to the question of how we should produce and supply electricity. However, there remains a large level of uncertainty over the pace and extent of deployment of such technologies, especially over the long term. With each passing year, detailed modelling and research studies are coming up with better estimates of how this can be done. Also, there remain various unknowns and potential disruptive technologies which would come into effect over the next few decades. But can we go on like this forever, or will other factors limit this approach?

Apart from making the supply as clean and renewable as possible, the scale of electricity production needs to be thought through. There is a view on the need to drive adoption of more decentralised renewable energy capacity like rooftop solar or solar agriculture feeders (as is being done in Maharashtra) and not just rely on large scale, centralised, renewable power plants. This not only allows for a reduced need for large transmission infrastructure and a decline in technical losses, but also for potentially greater democratic decision making and control over one’s energy resources.

In terms of pricing, it is high time that we acknowledge the real social cost of the existing energy system and begin internalising social and environmental externalities appropriately. This cannot be done overnight and will need greater awareness and consensus building, leading to a new form of social contract for the energy system. More importantly, it will need universal access to affordable and reliable modern forms of energy to be in place before such conversations proceed. Over time there is also a need to seriously engage with questions about the future like de-growth as well as equity across species and generations.⁹

Finally, there could be two approaches for planning and regulating the power system: The first would involve extracting maximum benefits from centralisation and large inter-connected transmission for better resource optimisation. The second would involve the significant decentralisation of decision making and control over time. In all likelihood, a combination of these approaches will point to a way forward.

Box 10.3: In the long run, how much energy do we need?¹⁰

How much energy we need for a decent standard of living for everyone is a question at the heart of energy planning, but rarely addressed. Generally, such estimation is based on a desired economic growth target or broader goals, and implicitly assumes that just so long as a particular amount of energy is generated, the developmental goals will automatically be met. However, even achieving this economic growth may not necessarily ensure satisfaction of everyone’s basic needs.

Therefore, energy planning should link energy and its end-use and end-user directly, promoting equity, and providing a better monitoring framework for energy use. End-use focused, bottom-up, disaggregated energy planning is such an approach that could be the basis of energy planning in the country. Bottom up, disaggregated approaches offer a good methodology for energy need projections.

First of all, they need a well-defined normative framework, which makes the developmental goals of energy planning explicit. Second, since they are based on calculating how much energy is needed for each developmental goal, the other side of the coin is that they lay out the distribution of the energy to specific end-uses (and end-users). The process by its very nature also indicates where and to which end-use and end-user the energy has to go - something that is as important to understand as the quantum of energy required. Along with this, the process can also offer insights into the best way to meet a particular developmental goal from the energy perspective, the relative criticality of energy as an input to meet the specific goal, and the policies and cross-sectoral linkages that are important to ensure that the energy used does indeed help meet the objectives. Finally, such an approach makes the monitoring of the implementation far more structured and relevant to developmental goals, and brings accountability to the energy planning process.

This framework reiterates the obvious but very powerful and often forgotten message - that this energy estimated for meeting basic needs will meet basic needs only if it goes to meet basic needs. One cannot allocate it for basic needs and then divert it for other purposes. Further, such bottom-up approaches can also help us to assess energy projections and plans in terms of their effectiveness in meeting developmental goals.

To summarise, the inevitable transition in the energy sector are mainly being driven by external technology and economic changes. Unless guided by conscious policy decisions, these changes will unfold chaotically, leaving the electricity sector and especially, the distribution companies, stranded with excess capacity and huge losses. Such a fallout will impact the small and rural consumers with serious implications for state level politics.

To avoid such consequences, it is extremely important to intervene at the earliest. The impending changes are uncertain and difficult to predict, and partly depend on the policy regulatory response. However, these can be turned into opportunities only if electricity sector regulators and policymakers begin acting at the earliest. If negotiated well, India could avoid many inefficient resource lock-ins with significant economic and environmental costs. India can chart a new exemplary development path in which it can provide its citizens with modern energy services without necessarily compromising on other resources such as land, air and water, while potentially opening up employment and investment opportunities in many new sectors associated with the transition. Whether India can rise up to this challenge, only time will tell.

Endnotes

¹ The norms have been notified but not yet implemented as of December, 2018.

² According to Bloomberg New Energy Finance, EV Outlook 2018, retrieved from https://about.bnef.com/electric-vehicle-outlook/

³ Today, around two thirds of freight and more than half of passenger traffic in Indian Railways is based on electric traction. Government plans to complete 100% electrification of broad-gauge routes by 2022. Please see: http://pib.nic.in/newsite/PrintRelease.aspx?relid=183399

⁴ Nikit, A., Gopal, A. R., Sheppard, C., Park, W. Y., & Phadke, A. A. (2017). Techno-economic assessment of deep electrification of passenger vehicles in India. Retrieved from https://ies.lbl.gov/publications/techno-economic-assessment-deep

⁵ See ‘Coal - sector update and outlook’, by CARE ratings, 2018, available at: http://www.careratings.com/upload/NewsFiles/Studies/Coal%20Yearly%20Update.pdf

⁶ India Smart Grid Forum. (2017, November). Smart grid handbook for regulators and policy makers. Retrieved from http://www.indiasmartgrid.org/reports/Smart%20Grid%20Handbook%20for%20Regulators%20and%20Policy%20Makers_20Dec.pdf

⁷ Solar feeder is a novel approach being implemented in Maharashtra to solarize agricultural electricity supply. It essentially involves setting up of tail end 1-10 MW solar plants connected to the substation where agriculture feeders have been separated.

⁸ Neslen, A. (2018, October 26). Spain to close most coalmines in € 250m transition deal. The Guardian. Retrieved from https://www.theguardian.com/environment/2018/oct/26/spain-to-close-most-coal-mines-after-striking-250m-deal

⁹ ‘De-growth’ denotes a form of society and economy which aims at the well-being of all and sustains the natural basis of life for which we need a fundamental transformation of our lives and extensive cultural change. The common values of a de-growth society should be care, solidarity and cooperation. Only this way, a self-determined life in dignity for all can be made possible. This also includes social changes and an orientation towards sufficiency instead of purely technological changes and improvements in efficiency in order to solve ecological problems. De-growth also strives for democratic decision making to allow for real political participation and the creation of open, connected and localised economies.

¹⁰ This box is summarised from the following report, How Much Energy Do We Need: Towards End-Use Based Estimation For Decent Living authored by Shripad Dharmadhikary and Rutuja Bhalerao. Retrieved from http://www.prayaspune.org/peg/publications/item/298

11 : Know your power

In this primer, we have explored the alphabet and grammar of the Indian electricity sector from a public interest viewpoint. We have explained key concepts and raised relevant questions but have desisted from passing judgement. We strongly believe that the task of guiding the sector should be carried out by a vigilant civil society which needs to be aware of its rights and responsibilities. But we do not present a blueprint for action. Instead, we suggest that citizens and civil society groups deploy the knowledge of the sector to find a path of action for themselves.

11.1 What have we learned?

We wrote this book with the objective of explaining the Indian power sector to lay readers as well as providing relevant knowledge to technical experts, thus equipping them to influence the present state and future of the sector. Our audience includes those interested in learning about the multi-disciplinary aspects of the sector, especially those who wish to engage in policy and regulatory proceedings from a public interest perspective. Our audience also includes public-spirited professionals and researchers in the sector, who may have expertise in some areas (technical, economic, management, legal or finance), but wish to develop a comprehensive perspective.

The power sector in India, and in fact in most countries, has been in a state of flux from the early 1990s. Sector reforms transformed the policy and institutional landscape of the sector, as described in Chapter 9. New reforms are being proposed by way of amending the E Act and associated policies. The country is witnessing a much awaited transformation with the widespread of rural and household electrification. Lakhs of households are getting connected to the grid for the first time. While this is a much desirable change, it brings along a new set of challenges to ensure sustainaible, affordable and reliable supply for all. As described in Chapter 10, there are also many challenges emerging from the expansion of the market, climate change mitigation measures and increasing renewable power generation. Reforms are proposed to meet these challenges, and it seems that the sector will be in a state of flux in the years to come. These changes affect society in complex ways in many areas: rapidly changing tariffs, reliability of supply, the impact on government budgets, the energy security of the country, social and environmental impacts, and shift of ownership of large assets from the public to the private sector. Several actors including officials, policy makers, regulators, and elected representatives make policy decisions that affect all of us. Citizens can influence the policy or regulatory decisions only if they understand the issues being debated.

In the preceding ten chapters, we have covered the fundamental technical, economic and institutional aspects of the Indian power sector. The power sector is quite complex in its operation and planning. We have attempted to cover many of the pertinent important issues comprehensively while emphasising the basic concepts and inter-linkages. We hope that the reader has a bird’s eye view of the sector after reading this primer, and is better equipped for further exploration and study.

11.2 Where are we?

While governments are introducing changes to meet present and future challenges, civil society groups, experts and unions of utility workers have recommended caution in this regard. There have been positive developments like rural electrification, reduction of power shortages, growth of renewable capacity and increase in transparency due to regulatory processes. But many challenges like financial losses of distribution companies and poor quality of supply remain. Therefore, these groups argue that several problems in policy making, planning and governance are responsible for the current state of the power sector. A rigorous and comprehensive approach is lacking, democratisation of governance has not been given sufficient attention, and planning and regulatory institutions have weakened. Vested interests - politicians, business, sector workers and consumers - continue to promote their self-interest. Small consumers are often underrepresented or misrepresented, and environmental concerns given the short shrift.

While reflecting on the reforms and challenges, some groups believe that reforms should be abandoned and the sector should go back to being controlled by public sector units. A complete backtracking is an unrealistic expectation in the current context and is perhaps not desirable, considering the known inefficiencies of the public sector. It often does not promote the public interest, and citizens and regulators find it difficult to hold it accountable.

Some groups argue for giving a free hand to the market and the private sector. They argue that competition and privatisation will reduce the cost of power generation and improve consumer services, thus benefitting the consumer. Given the nature of the electricity sector and the reality of the Indian political economy, one should have limited expectations about markets being able to solve all the problems of the sector. Firstly, the entire electricity sector may not be amenable to competition and markets, with segments such as transmission and the ‘wires’ part of distribution being considered natural monopolies. Secondly, the record of privatisation in the electricity sector and resultant improvements in efficiencies and reduction in costs is mixed at best, even in countries with better institutions and more robust markets than India.

As the debate between these two camps continues, we have a mixed model today, with most of the sector owned and operated by the government, but with a major shift towards private ownership in generation and slow growth in market operation. The state is no more the single dominant player in the power sector. There are many new players like private generators, private distribution companies, traders and regulators.

Regulatory commissions have been introduced at the central and state levels. They are expected to act as umpires in this field and uphold the wider interests of the sector. All acknowledge the need for stringent and independent regulation to regulate natural monopolies and keep in check the ‘non-competitive behaviour’ of some players. Public consultations are held while revising tariffs and finalising policy and plans. A positive development is the increasing use of the Right to Information (RTI) Act.

11.3. Where should we go from here?

Though no one person or organisation can provide a road map that will solve all the complex and interconnected problems of the sector, some solutions are obvious. Irrespective of ownership and market models, it is crucial that the public exercises control over policy making and governance.

On the policy front, there is a critical need to develop innovative ideas relevant to the local context, hold extensive consultations to incorporate people’s aspirations, and work with a comprehensive long term perspective, taking care of all the linkages to the sector. Rigorous approach to policy making and monitoring, independent of narrow short term electoral interests, is essential. This is true for any sector, but all the more important for the electricity sector, characterised by huge public investment and strong social impacts, as described in Chapter 8.

Democratisation of governance can happen only if there is capacity (C) in civil society, regulators, distribution companies and policy makers for informed engagement with the sector, complete transparency (T) in operation, accountability (A) not only to investors but also to the public, and meaningful public participation (P) in the sector. Capacity, Transparency, Accountability and Participation (CTAP, in short) are the keys to improving the governance of the sector.

How would the CTAP approach eliminate the ills that plague the sector? In order to address the problems, democratic spaces where public interest is represented and heard will need to be created and responsibly utilised. This would help people access key information, track the logic behind decisions, allow them to participate in decision making, and hold the decision makers accountable. Thus, a people-friendly CTAP approach can bring about effective control of governance functions by citizens which would orient the sector to serve the public interest. This approach would constitute the core of a strategy to keep the sector healthy.

Ensuring public contribution and oversight, as well as policy, planning and governance will address the interests of the vast majority of the poor as well as long term sustainability. This is all the more important in these times of flux. The sector is constantly facing new challenges, the regulatory system has passed its initial stage, experience with market models is limited, and the state has started withdrawing. As a result, the burden of guiding the sector falls on the shoulders of a vigilant civil society. Considering the enormous resources available to private corporations, consultants, international funding agencies and multinationals, it is essential that civil society organisations pool their strengths to raise the right questions and suggest alternatives to further the public interest agenda. In this effort, they also need to gather support from honest, committed professionals in the power sector who value its long term interests.

11.4. How can citizens engage with the sector?

In Chapter 1, we discussed the challenges facing the sector: low quality of supply to rural and small consumers, deteriorating health of distribution companies, the limitation of natural resources, and climate and ecological impacts. In order to overcome these challenges, we propose an approach called Reduce - Improve - Replace (RIR): Reduce the inequities in electricity use and luxury consumption, improve end use efficiency and sector governance, and replace conventional electricity sources with renewable and as far as possible distributed renewable sources. This RIR approach is similar to the Avoid-Shift-Improve approach in transport or the Preventive and Social Medicine approach in health care.

There are many groups - farmers, mass organisations, rural development organisations, industries, staff associations, consumer interest groups, project affected people, journalists, political parties, and professionals - working on issues affecting the power sector. Some of them fight to protect their individual interests. For example, farmers have the single demand of low or no tariff and increased hours of power supply, industries seek better quality supply and reduction of tariff, employees demand protection of their retirement benefits, and consumers resist payment of arrears. There are some who also pursue a broader agenda. Both problems which affect particular groups as well as broader issues are important. But it would be ideal if individual engagements come within the scope of the broad framework of the sector. Our aim is to increase the tribe of citizens and citizen researchers engaging with the sector using the RIR approach and increase their influence.

We hope that this primer will help such engagements in policy and governance. This could be achieved by filing petitions with the regulatory commissions or government, using tools like the RTI Act to increase accountability of all sector actors, writing articles in newspapers, or catalysing debates on different platforms. It is necessary that people from all walks of life - households, factories, farms, and academic and research institutes - join these debates. Debates based on actual field experiences, correct information, sharp analysis, evidence based critique of vested interests and creative ideas coupled with constructive suggestions can unravel the problems of the sector and provide sustainable solutions. Desirable aspects of policy need to be implemented and potentially problematic aspects need to be opposed and reversed.

The citizen groups need to seek basic data to avoid repeating past mistakes such as misallocation of thousands of crores of rupees due to the high AT&C loss to agricultural consumption or power purchase contracts that result in undue increase in the consumer tariff. It is important to avoid disasters like Enron and other high cost IPPs. Citizens need to ensure that promise of ‘24 x 7 power for all’ translates into action and does not remain a promise. To avoid tariff shocks, consumers need to question the appropriateness of demand forecasts and investment plans. There is a need to ensure that the revenue of the power sector worth lakhs of crores of rupees is used to further the public interest and not unfairly to further private interests. It is also important to understand the cross linkages in the sector. This includes ‘electricity supply, water and agriculture’, and ‘coal production, transport, environmental impact and power generation’.

To achieve these objectives, we cannot leave the power sector to experts, planners and decision-makers located in capital cities. If it is left solely to them, there are risks of costly failures and a neglect of the needs of the marginalised. It is we, the people, who will then have to bear the cost of putting the system back on the rails. It is important to reach out to as many people as possible and make them a part of the policy and regulatory process. As it is said, ‘if you are not part of the solution, you are part of the problem’. We hope that this primer is useful as the first step for all those who want to be a part of the solution. And may their tribe increase!

Reading and reference resources

Primers

Electricity Ancillary Services Primer, Reishus Consulting LLC. (2017, August), available at: http://nescoe.com/wp-content/uploads/2017/11/AnxSvcPrimer_Sep2017.pdf

Every day electricity, G Sreenivasan, Publications Division, 2017

Making competition work in electricity, Sally Hunt, John Wiley, 2002

Plugging people into power – An energy participation handbook, Northwest Conservation Act Coalition, USA, 1993

Power Primer: A non-technical guide from generation to end use, Ann Chambers, PennWell, USA, 1999

Sustainable Energy - without the hot air, David JC MacKay, UIT, Cambridge, UK, 2009 (www.withouthotair.com)

The people’s power guide, People’s organisation for Washington’s energy resources, USA, 1982

Understanding the supply of electricity, KR Padiyar, BS Publications, 2014

Technical concepts

Electric Energy Systems Theory – An Introduction – Second Edition, OI Elgerd, Tata Mcgraw-Hill, 2017

Electric Power Systems, 5th Edition, BM Weedy and others, Wiley, 2012

Fundamentals of Physics – Vol 2, Electricity & Magnetism, Resnick, Halliday and Walker, Wiley, 2011

Grid Integration of Renewables in India: An Analysis of Forecasting, Scheduling and Deviation Settlement Regulations for Renewables, Prayas, 2016, available at: http://www.prayaspune.org/peg/publications/item/327-grid-integration-of-renewables-in-india.html

India Electricity Grid Code, CERC, 2010, available at: http://www.cercind.gov.in/2016/regulation/9.pdf

Modern power plant engineering, J Weisman and R Eckart, Prentice-Hall India, 1985

Modern Power System Analysis – Fourth Edition, Kothari DP and Nagrath IJ, McGraw Hill, 2011

Power Generation, Operation, and Control, 3rd Edition, Allen J. Wood, Bruce F. Wollenberg, Gerald B. Sheblé, Wiley, 2013

Power System Flexibility for The Energy Transition, IRENA report 2018, available at: https://irena.org/-/media/Files/IRENA/Agency/Publication/2018/Nov/IRENA_Power_system_flexibility_1_2018.pdf

The Feynman Lectures on Physics: Volume II: Electromagnetism and Matter, Pearson Education India 2012

Understanding Physics Light, Magnetism and Electricity, Issac Assimov, Walker, 1966

Water power engineering, MM Dandekar and KN Sharma, Vikas Publishing House, 2013

Financial, economic and tariff concepts

A Refresher on Internal Rate of Return, by Amy Gallo, Harvard Business Review, March 17, 2016, available at: https://hbr.org/2016/03/a-refresher-on-internal-rate-of-return

Central Electricity Regulatory Commission (Terms and Conditions for Tariff determination from Renewable Energy Sources) Regulations, 2017. http://www.cercind.gov.in/2017/regulation/Noti131.pdf

Central Electricity Regulatory Commission (Terms and Conditions of Tariff) 2014: http://www.cercind.gov.in/2014/regulation/reg21.pdf

Energy Economics: Concepts, Issues, Markets and Governance, By Subhes C. Bhattacharyya, Springer, 2011

How We Happened to Sell Off Our Electricity, James Meek, London Review podcast, 2012, available at: https://www.lrb.co.uk/v34/n17/james-meek/how-we-happened-to-sell-off-our-electricity

Maharashtra Electricity Regulatory Commission (Multi Year Tariff) Regulations, 2015: http://www.mercindia.org.in/pdf/Order%2058%2042/MYT%20Regulations%202015_Gazette.pdf (Check latest version of similar regulations for your state)

Maharashtra Electricity Regulatory Commission (Terms and Conditions for Determination of Renewable Energy Tariff) Regulations, 2015: http://www.mercindia.org.in/pdf/Order%2058%2042/MERC(TandC%20for%20Determination%20of%20RE%20Tariff)%20Regulations,%202015%20.pdf (Check latest version of similar regulations for your state)

Maharashtra Electricity Regulatory Commission (Standards of Performance of Distribution Licensees, Period for Giving Supply and Determination of Compensation) (First Amendment) Regulations, 2017: http://www.mercindia.org.in/pdf/Order%2058%2042/SoP%20(First%20Amendment)%20Regulations%202017.pdf (Check latest version of similar regulations for your state)

State performance based regulation using multiyear rate plans for U.S. Electric Utilities, Lowry MN et al, Lawrence Berkeley National Laboratory, USA, 2017, available at: https://eta.lbl.gov/sites/default/files/publications/multiyear_rate_plan_gmlc_1.4.29_final_report071217.pdf

Tariff Policy 2016, Ministry of Power, available at: http://www.kseboa.org/download/government-orders/national-tariff-policy-resolution-dated-28-01-2016.html

The Lesser Known Tariff: Fuel Surcharge Levy in Indian States, Prayas 2017, available at: http://prayaspune.org/peg/publications/item/365-the-lesser-known-tariff-fuel-surcharge-levy-in-indian-states.html

Legal, policy, planning and regulatory resources

A new world: the geopolitics of the energy transformation http://geopoliticsofrenewables.org/assets/geopolitics/Reports/wp-content/uploads/2019/01/Global_commission_renewable_energy_2019.pdf

Advanced Energy Storage In Integrated Resource Planning (IRP) 2018 Update, Energy Storage Association, http://energystorage.org/IRP

Black and Dirty: The real challenges facing India’s coal sector. Prayas 2013. Available at: http://www.prayaspune.org/peg/publications/item/191-black-and-dirtythe-real-challenges-facing-india%E2%80%99s-coal-sector.html

California Energy Crisis and Lessons for India, A K N Reddy, EPW Vol.36 No.18, May 5, 2001

Clean energy technologies threaten to overwhelm the grid. Here’s how it can adapt. Roberts, D. 2018. Available at: https://www.vox.com/energy-and-environment/2018/11/30/17868620/renewable-energy-power-grid-architecture

Dams and development, the report of the World Commission on Dams (http://www.dams.org), Earthscan, 2000

Draft National Electricity Plan - Transmission, CEA, available at: http://www.cea.nic.in/reports/others/ps/pspa2/draft_nep_trans_2016.pdf

Electric power distribution, AS Pabla, Tata McGraw Hill, 2001

Electricity (Supply) Act, 1948

Electricity Act, 2003

Electricity Distribution Companies in India: Preparing for an uncertain future. Prayas 2018. Available at: http://prayaspune.org/peg/publications/item/377

Electricity Power Survey (19th), Central Electricity Authority (CEA), 2017

Electricity Regulation in the US: A Guide, Regulatory Assistance Project (RAP), USA, 2016, available at http://www.raponline.org/wp-content/uploads/2016/07/rap-lazar-electricity-regulation-US-june-2016.pdf

Electricity Regulatory Commissions Act, 1998

Electrifying India: Regional Political Economies of Development, Sunila Kale, Stanford University Press, 2014

Energy for a Sustainable World, Goldenberg J, Thomas B Johnsson, Amulya KN Reddy, RH Williams, Wiley Eastern, New Delhi, 1990

Energy, development and climate change, Chapter by Prayas in the book ‘Handbook of climate change and India’, Edited by Navroz K Dubash, Oxford University Press, 2012 (revised edition expected soon)

Ensuring electricity for all, Prayas, 2013, available at: http://www.prayaspune.org/peg/publications/item/load/486_4235f87c0f2889116031a8a98393b331.html

Fixated on Megawatts: Urgent Need to Improve Power Procurement and Resource Planning, Centre for Energy, Environment and Regulation, (CEER), 2018, available at: http://www.ceer.in/system/UploadDir/publication/main/1535098171_fixatedonmegawatts.pdf

Flexibility Solutions for High-Renewable Energy Systems by BNEF, https://about.bnef.com/blog/flexibility-solutions-high-renewable-energy-systems/

Global Experience with Electricity Reform – A collection of 9 articles edited by Navroz Dubash and Daljit Singh, EPW, December 10, 2005

Growth of Electricity Sector in India from 1947 to 2018, CEA, available at: http://cea.nic.in/reports/others/planning/pdm/growth_2018.pdf

How Much Energy Do We Need: Towards End-Use Based Estimation for Decent Living, Prayas (Energy Group), 2015, available at http://prayaspune.org/peg/publications/item/298.html

How much energy do we need: Towards end-use based estimation for decent living, Prayas, 2015, available at: http://prayaspune.org/peg/publications/item/298.html

Integrated Energy Planning: Part I. The DEFENDUS Methodology, Amulya K N Reddy et al., 1995, available at http://amulya-reddy.org.in/Publication/DEFENDUS%20-%20Part%20I.pdf

Integrated Energy Policy, Planning Commission, 2006, available at: http://planningcommission.gov.in/reports/genrep/rep_intengy.pdf

Least-Cost Power Planning: Case Study of Maharashtra state, Prayas (Energy Group), 2000, available at http://www.prayaspune.org/peg/publications/item/89-least-cost-power-planning-case-study-of-maharashtra-state.html

Load Generation Balance Reports of CEA, available at CEA website. 2018 report available at: http://www.cea.nic.in/reports/annual/lgbr/lgbr-2018.pdf

Managing_the_Coal_Capital_Transition_2018 by Rocky Mountain Institute, https://www.rmi.org/managing-coal-capital-transition/

Manual on Transmission Planning Criteria, CEA, 2013, available at: http://cea.nic.in/reports/others/ps/pspa2/tr_plg_criteria_manual_jan13.pdf

Many Sparks but Little Light: The Rhetoric and Practice of Electricity Sector Reforms in India. Prayas 2017. Available at: http://www.prayaspune.org/peg/publications/item/332.html

National Electricity Plan - Volume 1 on generation, CEA, available at: http://cea.nic.in/reports/committee/nep/nep_jan_2018.pdf

Power Play, Abhay Mehta, Orient Longman, Hyderabad, 2000

Power Politics: Equity and Environment in Electricity Reform. Dubash, N. K. (Ed.). (2002).World Resources Institute. Available at: https://www.wri.org/publication/power-politics

Report of the Comptroller and Auditor General of India on Environmental Clearance and Post Clearance Monitoring. Available at https://www.cag.gov.in/content/report-39-2016-ministry-environment-forest-and-climate-change-performance-audit#Union%20Government%20Chapter%207%20Post%20Environment%20Clearance%20Monitoring%20by%20Regional%20Offices%20Report%2039

Report of the expert committee on fuels for power generation, CEA, 2004, summary available at: http://www.cea.nic.in/reports/others/thermal/tppd/expert_committee_report_fuel.pdf

Structures of Power: Electrification in Colonial India. Comparative Studies of South Asia, Africa and the
Middle East, 34(3), 454-475. Kale, S. S. (2014).
Available at: http://citeseerx.ist.psu.edu/viewdoc/download?doi=10.1.1.867.6344&rep=rep1&type=pdf

The future electricity grid: Key guides and considerations for developing countries. Jairaj, B., Martin, S., Ryor, J., Dixit, S., Gambhir, A., Chunekar, A., Wang, T. World Resources Institute 2016. Available at: World Resources Institute Website: https://www.wri.org/publication/future-electricity-grid

The Future of Electricity Resource Planning, Lawrence Berkeley National Laboratory (LBNL), USA, 2016, available at: http://eta-publications.lbl.gov/sites/default/files/lbnl-1006269.pdf

The power of promise – Examining nuclear energy in India, M V Ramana, Penguin Viking, 2012

The Practice and Politics of Regulation: Regulatory Governance in Indian Electricity. Dubash, N. K., & Rao, D. N. (2007). Macmillan India.

The Price of Plenty: Insights from 'Surplus' Power in Indian States, Prayas (Energy Group), 2017, available at: http://prayaspune.org/peg/publications/item/335-
the-price-of-plenty-insights-from-surplus-power-in-indian-states.html

Transforming Electricity Governance in India: Has India’s Power Sector Regulation Enabled Consumers’ Power?, Khanna, A., Singh, D., Swain, A., & Narain, M. (Policy Research Working Paper 7275). World Bank Energy and Extractives Global Practice Group.2015 Available at: http://documents.worldbank.org/curated/en/204051467992481497/pdf/WPS7275.pdf

Electricity and energy data

Annual integrated rating of DISCOMs, PFC, available at: http://www.pfcindia.com/Home/VS/25

Estimated average rates of electricity, Average tariffs in different states, CEA, available at: http://cea.nic.in/fsanda.html, http://cea.nic.in/reports/others/enc/fsa/tariff_2014.pdf

Executive Summary of Power sector, CEA monthly report, available at: http://cea.nic.in/monthlyexesummary.html

General review – All India Electricity statistics, CEA, to be purchased, details at: http://cea.nic.in/annualreports.html

Growth of electricity sector in India, CEA, available at: http://cea.nic.in/pdm.html

Growth of Indian electricity sector 1947-2018, Central Electricity Authority, 2018

India energy dashboard, giving energy supply and end-use data: http://indiaenergy.gov.in/edm/

International Energy Agency – reports and country statistics, available at: https://www.iea.org/countries/India/. Specifically, see India Energy Outlook report 2015, available at: https://webstore.iea.org/weo-2015-special-report-india-energy-outlook

Load Generation Balance Report, CEA, available at: http://cea.nic.in/annualreports.html

Market Monitoring Reports. CERC. Available at: http://www.cercind.gov.in/report_MM.html

Performance Report of State Power Utilities, PFC, available at: http://www.pfcindia.com/Home/VS/29

Power ministry – links to many dashboards – Rural electrification (DDUGJY, SAUBHAGYA), Financial bailout (UDAY), Power for All, National Power Portal, Merit order dispatch (MERIT), Transmission dashboard (Tarang), LED dashboard (UJALA), Urban distribution – IPDS dashboard (URJA), Power Exchange data (Vidyut Pravah), Rural feeder monitoring (RFMS), National e-bidding portal (DEEP) : https://powermin.nic.in/

Renewable Energy Data Portal, Prayas, available at: http://prayaspune.org/peg/re.html

TERI Energy & Environment Data Diary and Yearbook (TEDDY), TERI, 2016-17

The Environment Clearance Database. Available at: http://environmentclearance.nic.in/ https://parivesh.nic.in/ (EC, FC, Wildlife and CRZ clearances)

The Forest Clearance Database. Available at: http://forestsclearance.nic.in/https://parivesh.nic.in/ (EC, FC, Wildlife and CRZ clearances)

Trading Licensees Registry. CERC. Available at:
http://www.cercind.gov.in/Trading-Licensees.html

Consumer guides, resources and awareness material

10 Questions to Ask about Integrated Resources Planning, Prayas (Energy Group) and World Resources Institute (WRI), 2014, available at: http://www.prayaspune.org/peg/publications/item/274-10-questions-to-ask-about-integrated-resources-planning.html

Alternative Power Planning, Prayas (Energy Group) and Kalpavriskh, 2007, available at: http://www.prayaspune.org/peg/publications/item/63-alternative-power-planning.html

Awareness and Action for Better Electricity Service - An agenda for the community –(English and Hindi), Prayas 2008 : Awareness and Action for Better Electricity Service - An agenda for the community - English

Calculate your bill, Bijlibachao: https://www.bijlibachao.com/electricity-bill/online-electricity-bill-calculator-for-all-states-in-india.html

Consumer's Guide for Electricity Service - Information on consumer related rules and regulations, Prayas 2010: http://prayaspune.org/peg/publications/item/86-consumers-guide-for-electricity-service-information-on-consumer-related-rules-and-regulations.html

Demanding Electricity Service: A Guide for the Community Activist, (English and Hindi), Prayas 2015: http://prayaspune.org/peg/publications/item/300.html

Electricity for All: Ten Ideas towards Turning Rhetoric into Reality - A Discussion Paper, (English and Hindi) Prayas 2010: http://prayaspune.org/peg/publications/item/84.html

Electricity safety awareness video, IEEE – Hyderabad 2012, available at: https://www.youtube.com/watch?v=a_7rRUxhvVs

Marathi Booklet: “Veej Grahakanchya Mahiteesathi” - Legal provisions, rights and procedure for electricity service, Prayas 2008: http://prayaspune.org/peg/publications/item/70-marathi-booklet-%E2%80%9Cveej-grahakanchya-mahiteesathi%E2%80%9D-legal-provisions-rights-and-procedure-for-electricity-service.html

Prayas tool for DISCOM financial analysis – RATE: http://prayaspune.org/peg/resources/revenue-and-tariff-analysis-for-electric-utilities-rate-model-for-andhra-pradesh.html

Websites

Amulya KN Reddy publications: www.amulya-reddy.org.in

Asian Development Bank – India, https://www.adb.org/countries/india/main

BHEL, http://www.bhel.com/

Bijli Bachao! https://www.bijlibachao.com/

Body of knowledge on infrastructure regulation (Developed by the Public Utility Research Center (PURC) at the University of Florida, in collaboration with the University of Toulouse, the Pontificia Universidad Catolica, the World Bank and a panel of international experts), http://regulationbodyofknowledge.org

Brookings India, https://www.brookings.in/

Bureau of Energy Efficiency: https://www.beeindia.gov.in/

Center for Study of Science, Technology & Policy, http://www.cstep.in/

Central Electricity Authority: http://cea.nic.in/index.html

Central Electricity Regulatory Commission, www.cercind.org

Confederation of Indian Industry – Energy, https://www.cii.in/Sectors.aspx?enc=prvePUj2bdMtgTmvPwvisYH+5EnGjyGXO9hLECvTuNu5TglXym+K0ZoMVBS71Qkl

Consumer Unity & Trust Society: http://www.cuts-international.org/

Council on Energy, Environment and Water, https://www.ceew.in/

CPR Mapping Power Project, see http://www.cprindia.org/projects/mapping-power

Electricity Supply Monitoring Imitative and Monitoring and Analysis of Residential Electricity Consumption: http://watchyourpower.org/

Energy Analytics Lab – IIT – Kanpur. Has real time data on Indian power sector https://eal.iitk.ac.in/

Forum of Regulators: http://www.forumofregulators.gov.in/

Gram Oorja, https://gramoorja.in/

Husk Power Systems, http://www.huskpowersystems.com/

International Energy Agency: https://www.iea.org/

International Renewable Energy Agency (IRENA), https://www.irena.org/

KSEB officers Association: http://www.kseboa.org/

Ministry of New and Renewable Energy: https://mnre.gov.in/

Ministry of Power, with links to all other power related websites: www.powermin.nic.in

Natural Resources Defense Council – India, https://www.nrdc.org/india

NITI Aayog, https://www.niti.gov.in/

NTPC Limited, http://www.ntpc.co.in

People’s Monitoring Group on Electricity Regulation, http://pmger.org/

Planning Commission, archived website, http://planningcommission.gov.in/index_oldpc.php

Power Finance Corporation, http://www.pfcindia.com/

Power Grid Corporation of India Limited, http://www.powergridindia.com/

Power System Operation Corporation Limited, https://posoco.in/

Prayas (Energy Group): www.prayaspune.org/peg

Regional Load Dispatch Centre (North, East, West, South, North-East)- https://nrldc.in/, https://erldc.in/, http://www.wrldc.in/, http://www.srldc.in/, http://www.nerldc.org/

Rural Electrification Corporation Limited, https://www.recindia.nic.in/

SELCO India, http://www.selco-india.com/

State Electricity Regulatory Commissions: http://www.forumofregulators.gov.in/Weblinks.aspx

State Load Dispatch Centres, for example Maharashtra: https://mahasldc.in/home.php

The Energy Resources Institute: http://www.teriin.org/

World Bank: http://www.worldbank.org

World Resources Institute – India, https://wri-india.org/

Abbreviations

A

Amperes

ABR

Average Billing Rate

ABT

Availability Based Tariff

AC

Alternating Current

ACoS

Average Cost of Supply

ADB

Asian Development Bank

AGC

Automatic Generation Control

AHEC

Alternate Hydro Energy Centre

AMR

Automatic Meter Reading

APL

Above Poverty Line

APTEL

Appellate Tribunal for Electricity

ARR

Annual Revenue Requirement

AT&C Loss

Aggregate Technical & Commercial Loss

BBMB

Bhakra Beas Management Board

BCR

Benefit-Cost Ratio

BEE

Bureau of Energy Efficiency

BHEL

Bharat Heavy Electricals Limited

BIS

Bureau of Indian Standard

BOO

Build, Own and Operate

BPL

Below Poverty Line

BSES

Bombay Suburban Electricity Supply

BTU

British Thermal Unit

C

Coulomb

CAC

Central Advisory Committee

CAD

Current Account Deficit

CAG

Comptroller and Auditor General

CB

Circuit Breaker

CCGT

Combined Cycle Gas Turbine

CEA

Central Electricity Authority

CERC

Central Electricity Regulatory Commission

CFA

Centre for Financial Accountability

CGRF

Consumer Grievance Redressal Forum

CHP

Combined Heat and Power

CIL

Coal India Limited

CIRE

Central Institute for Rural Electrification

CMD

Chairman and Managing Director

CMPSA

Coal Mines (Special Provisions) Act

CPCB

Central Pollution Control Board

CPP

Captive Power Plant

CTAP

Capacity, Transparency, Accountability and Participation

CTU

Central Transmission Utility

CUF

Capacity Utilisation Factor

DAE

Department of Atomic Energy

DC

Direct Current

DCC

Distribution Control Centre

DDUGJY

Deen Dayal Upadhyaya Gram Jyoti Yojana

DEEP

Discovery of Efficient Electricity Price

DF

Diversity Factor

DGH

Directorate General of Hydrocarbons

DISCOM

Distribution Company

DSCR

Debt Service Coverage Ratio

DSM

Demand Side Management/Deviation and Settlement Mechanism

DT

Distribution Transformer

DVC

Damodar Valley Corporation

EAC

Environment Appraisal Committee

E Act

Electricity Act 2003

EC

Environment Clearance

EESL

Energy Efficiency Services Limited

EHT

Extra High Tension

EHV

Extra High Voltage

EIA

Environment Impact Assessment

EMI

Equated Monthly Instalment

EPC

Engineering, Procurement and Construction

EPS

Electric Power Survey

ERC

Electricity Regulatory Commission

ESP

Electro Static Precipitator

EV

Electric Vehicle

EXIM

Export Import

FACT

Flexible AC Transmission System

FC

Forest Clearance

FDI

Foreign Direct Investment

FGD

Flue Gas Desulphurisation

FGMO

Free Governor Mode of Operation

FiT

Feed-in-Tariff

FoIR

Forum of Indian Regulators

FoLD

Forum of Load Despatchers of India

FoR

Forum of Regulators

FRL

Full Reservoir Level

GDP

Gross Domestic Product

GE

General Electric

GENCO

Generation Corporation

GHG

Green House Gases

GIS

Gas Insulated Substation

GNA

General Network Access

GoM

Government of Maharashtra

GST

Goods and Services Tax

GW

Giga Watt

HDI

Human Development Index

HELP

Hydrocarbon Exploration and Licensing Policy

HP/hp

Horse Power

HRSG

Heat Recovery Steam Generator

HT

High Tension

HVAC

High Voltage Alternating Current

HVDC

High Voltage Direct Current

HVDS

High Voltage Distribution System

ICT

Information and Communication Technologies

IDC

Interest During Construction

IEA

International Energy Agency

IEGC

Indian Electricity Grid Code

IEX

Indian Energy Exchange

IMF

International Monetary Fund

InSTS

Intra-State Transmission System

InWEA

Indian Wind Energy Association

IPCC

International Panel on Climate Change

IPDS

Integrated Power Development Scheme

IPP

Independent Power Producer

IREDA

Indian Renewable Energy Development Agency

IRP

Integrated Resource Planning

IRR

Internal Rate of Return

ISTS

Inter-State Transmission System

JBIC

Japan Bank of International Corporation

JNNSM

Jawaharlal Nehru National Solar Mission

kcal

Kilo Calorie

KG-D6

Krishna Godavari Dhirubhai 6

kWh

kilo Watt hour or Unit

LCC

Life Cycle Cost

LCOE

Levelised cost of energy

LDC

Load Dispatch Centre

LED

Light Emitting Diode

LF

Load Factor

LNG

Liquefied Natural Gas

LoA

Letter of Assurance

LOLP

Loss of Load Probability

LPG

Liberalisation Privatisation and Globalisation

LT

Low Tension

LVDC

Low Voltage Direct Current

MaaS

Mobility as a Service

mAh

milli Ampere hour

MBTU

Million British Thermal Unit

MCB

Miniature Circuit Breaker

MCR

Maximum Continuous Rating

MDDL

Minimum Draw Down Level

MNRE

Ministry of New and Renewable Energy

MoC

Ministry of Coal

MOD

Merit Order Dispatch

MoEFCC

Ministry of Environment, Forests and Climate Change

MoP

Ministry of Power

MoPNG

Ministry of Petroleum and Natural Gas

MoU

Memoranda of Understanding

MTCE

Million Tonnes of Coal Equivalent

MTOE

Million Tonnes of Oil Equivalent

MTPA

Million Tonnes Per Annum

MU

Million Unit

MW

Mega Watts

MYT

Multi-Year Tariff

NBFI

Non Banking Financial Institution

NCDP

New Coal Distribution Policy

NCRB

National Crime Records Bureau

NDC

Nationally Determined Contribution

NEEPCO

North Eastern Electric Power Corporation

NELP

New Exploration Licensing Policy

NEMMP

National Electric Mobility Mission Plan

NEP

National Electricity Plan

NERC

North American Electricity Reliability Council

NGT

National Green Tribunal

NHPC

National Hydroelectric Power Corporation

NITI Aayog

National Institution for Transforming India

NLC

Neyveli Lignite Corporation

NLDC

National Load Dispatch Centre

NOx

Nitrogen Oxides

NPA

Non-Performing Asset

NPC

National Power Committee

NPCC

Northeast Power Coordinating Council

NPCIL

Nuclear Power Corporation of India Limited

NPTI

National Power Training Institute

NPV

Net Present Value

NSEFI

National Solar Energy Federation of India

NTPC

National Thermal Power Corporation

O&M

Operation and Maintenance

OCGT

Open Cycle Gas Turbine

ONGC

Oil and Natural Gas Corporation Limited

PAT

Perform-Achieve-Trade

PF

Power Factor

PFA

Power for All

PFC

Power Finance Corporation

PI

Profitability Index

PLF

Plant Load Factor

PMU

Phasor Measurement Unit

PNGRB

Petroleum and Natural Gas Regulatory Board

PoC

Point of Connection

POSOCO

Power System Operation Corporation

POWERGRID

Power Grid Corporation of India Limited

PPA

Power Purchase Agreement

PPP

Public-Private Partnership

PSS

Pumped Storage Station

PTC

Power Trading Corporation of India Limited

PV

Photo Voltaic/Present Value

PXIL

Power Exchange India Limited

R&R

Resettlement and Rehabilitation

RDF

Refuse Derived Fuel

RE

Renewable Energy

REC

Rural Electrification Corporation

RGGPL

Ratnagiri Gas and Power Private Limited

RGGVY

Rajiv Gandhi Grameen Vidyutikaran

Yojana

RGMO

Restricted Governor Mode of Operation

RIL

Reliance Industries Limited

RIR

Reduce-Improve-Replace

RLDC

Regional Load Dispatch Centre

RoE

Return on Equity

RoW

Right of Way

RPC

Regional Power Committee

RPM

Revolutions Per Minute

RPO

Renewable Purchase Obligation

RTI

Right to Information

S&L

Standards and Labelling

SAC

State Advisory Committee

SAUBHAGYA

Sahaj Bijli Har Ghar Yojana

SBI

State Bank of India

SCCL

Singareni Coal Collieries Limited

SEAC

State or Union Territory Level Expert Appraisal Committee

SEB

State Electricity Board

SECI

Solar Energy Corporation of India

SEGC

State Electricity Grid Code

SEIAA

State Environment Impact Assessment Authority

SERC

State Electricity Regulatory Commission

SEZ

Special Economic Zone

SHAKTI

Scheme for Harnessing and Allocating Koyala Transparently in India

SHR

Station Heat Rate

SLDC

State Load Dispatch Centre

SNA

State Nodal Agency

SOx

Sulphur Oxides

SPCB

State Pollution Control Board

SPDA

Solar Power Developers Association

SPV

Special Purpose Vehicle

SRISTI

Sustainable Rooftop Implementation for Solar Transfiguration of India

STC

Standard Test Condition

STU

State Transmission Utility

Sub- LDC

Sub Load Dispatch Centre

SuTRA

Sustainable Transformation of Rural Areas

SVC

Static VAR Compensator

T&D

Transmission and Distribution

TAPI

Turkmenistan-Afghanistan-Pakistan-India

THDC

Tehri Hydro-Development Corporation

ToD

Time of the Day

TRANSCO

Transmission Corporation

UDAY

Ujwal DISCOM Assurance Yojana

UHVDC

Ultra High Voltage Direct Current

UI

Unscheduled Interchange

UJALA

Unnat Jyoti by Affordable LEDs for All

UMPP

Ultra Mega Power Project

UPS

Uninterruptible Power Supply

UT

Union Territory

UTPCC

Union Territories Pollution Control Committee

V

Volts

V2G

Vehicle-to-Grid

VA

Volt Ampere

VAR

Volt-Ampere Reactive

W

Watts

WACC

Weighted Average Cost of Capital

Wp

Watt peak

Glossary

Accounting Rate of Return

The accounting rate of return is a metric for comparing investment options and is calculated by dividing the average annual profit by the initial value of the asset.

Additional Surcharge

It is a charge on open access consumers to compensate the DISCOMs for generation capacity that is underutilised due to fall in demand, which is attributable to loss of sales via open access.

Aggregate Technical

and Commercial

(AT&C)

Is a measure of total losses in distribution and has two components – technical and commercial. It is the difference between energy available for sale and energy for which payments are received.

Automatic Meter Reading (AMR)

Feeders, Distribution Transformers or consumers can be equipped with automatic meter reading (AMR) which can periodically measure and send energy data to a central location, without manual intervention.

Ancillary Services

In relation to power system (or grid) operation, the services necessary to support the power system (or grid) operation in maintaining power quality, reliability and security of the grid, e.g. active power support for load following, reactive power support, black start, etc.

Automatic Generation Control (AGC)

A regulatory mechanism and set of equipment that provides for automatically adjusting generation within a balancing area from a centralized location to maintain a specified frequency and/or scheduled interchange.

Auxiliary Consumption

It is the energy consumed by the equipment which is required to operate the power plant. This includes fuel conveyers, pumps, pollution control equipment, lights, etc. It is usually expressed as a percentage of the energy generation.

Availability

It is the measure of the actual capacity available for generating power. For a generating unit, it is calculated as the average of the declared available generating capacity over a period of time (typically a year).

Availability Based Tariff (ABT)

An arrangement to rationalise tariff for supply or withdrawal of power from the grid. When applied to generators, has three components: capacity charge - based on committed generation capacity; energy charge - based on committed energy generation; and unscheduled interchange charge - based on the deviation of energy supply and frequency. Can be applied to bulk buyers also, in which case, generation is replaced by withdrawal.

Average Billing Rate (ABR)

A measure of the average revenue received per unit of energy sold. ABR is usually calculated for each consumer category and also for total energy sold.

Average Power Purchase Cost (APPC)

This is expressed in Rs/Unit and is calculated by dividing the total cost of power purchase (Rs) by the total quantum of power purchase (Units) of the distribution company, from various generating sources and market.

Average Cost of Supply (ACoS)

It is the amount that would be paid to the distribution company by all consumers if they were all charged the same tariff.

Benefit-Cost Ratio (BCR)

This ratio is calculated by dividing the present value of the benefits by the present value of the costs. It is also referred to as Profitability Index (PI) since the ratio gives the value of how much profit is made, given the cost.

Bus Bar

It is a set of lines (one line for each of the three phases) at one voltage level to which many connections are made.

Billing Efficiency

The ratio of Energy billed to the Energy input.

Calorific Value

The calorific value (also called heating value) of a fuel is equal to the heat released when one kg of fuel is burnt and is measured in kcal/kg.

Capacity Utilisation Factor (CUF)

A measure of the productivity of generation, usually used for renewable energy generation plants like wind or solar. It is the ratio of the gross actual energy generated by the plant to the maximum possible energy that can be generated with the plant working at its full rated power capacity for all the time.

Capital Cost

This is the cost incurred for equipment and construction of a project. This includes the cost of land, engineering, procurement, construction, overheads, and interest during construction.

Capital Expenditure

Capital expenditure is the expenditure undertaken to create capital assets, i.e. to acquire a building, buy new equipment, etc. Capital expenditure is spread over the life of the project for recovery and is not recovered lump-sum.

Capitalisation

Within a certain time period, the expenditure that is actually incurred for addition of (a part or the whole) of the capital expenditure to the asset base of a company.

Captive Coal Block

A coal block associated with a specific end-use plant.

Carriage and Content

They refer to two separate functions of a company that manages electricity distribution as well as electricity supply. Carriage (also called ‘wires’) refers to the physical infrastructure required to supply electricity such as distribution transformers, cables, poles and so on. Content (also called ‘supply’) refers to the electricity that is supplied through the physical infrastructure.

Circuit Breaker

It is an elaborate switch used at high voltages and currents.

Collection Efficiency

The ratio of revenue collected from consumers to the billed amount.

Combined Cycle Gas Turbine

Combined Cycle Gas Turbine (CCGT) are gas based generating stations, which have a few gas based turbines and the hot exhaust from these are used to produce steam, to operate steam turbines.

Consumer Grievance Redressal Forum

(CGRF)

Set up by the distribution company to address consumer complaints. Typically has four members, of which three are appointed by the company and the fourth by the SERC to represent consumers.

Consumer Representatives

Persons authorised to represent interests of consumers in proceedings before the regulatory commission as per Section 94(3) of the Electricity Act, 2003.

Cost of Conserved Energy

An investment metric to compare conservation measures among themselves and against competing energy supply options.

Cost-Plus Tariff

Under ‘cost-plus’ regulation, the tariff is set such that the company (generation, transmission or distribution company) is allowed to recover all its prudent costs plus is provided with a reasonable rate of return. Prudent cost implies that the expenditure was undertaken after evaluating all possible alternatives and choosing the least cost one out of them. The ‘cost-plus’ method, also known as the ‘rate of return’ regulation or ‘cost of service’ regulation, is commonly used to regulate the consumer prices in monopoly industries.

Cross-Subsidy

Some consumers have tariff above the average cost of supply. These consumers cross-subsidise consumers who have a lower tariff.

Cross-Subsidy Surcharge

Cross-subsidy surcharge is levied on open access consumers and distribution licensees to compensate the distribution company for loss of cross-subsidy due to migration of large consumer to open access.

Demand Response

Demand response allows consumers to respond to the DISCOMs need to reliably balance supply and demand, especially at times of peak load. This is done by consumers voluntarily by shifting their load to off-peak times for which they receive some form of compensation.

Demand Side Management

Demand-side management and demand response enable consumers to participate in load control based on price signals.

Depreciation

It represents the reduction in the value of the asset due to ageing and use.

Deviation and Settlement Mechanism (DSM)

Regulations to maintain grid discipline and grid security as envisaged under the grid code through the commercial mechanism of deviation settlement through drawal and injection of electricity by users of the grid.

Discount Rate

People value money today over the same amount of money in the future. This is because there is an opportunity cost of capital, i.e. money has the potential to grow in value. This is captured by the metric of discount rate. It is used to discount future cash flows to calculate their present value.

Distribution Circle

An administrative unit of a distribution company, typically covering a district or part of a large city.

Distribution Franchisee

Private participation through franchisees is a means of outsourcing various functions of the DISCOM. An input based franchisee is a type of franchisee model in which the DISCOM continues to provide supply but all the other distribution functions such as metering, billing, capital expenditure for maintaining the network are undertaken by the franchisee.

Diversity Factor

Ratio between the total individual peak demands of many consumers to the system peak demand. This will be 1 if all consumers have peak demand at the same time.

Electrical Inspectorate

Set up by the state government, it is responsible for electrical safety and inquiring into electrical accidents.

Electricity Act

(E Act)

Enacted in 2003, the Electricity Act or E Act replaces all previous Acts and provides the legal framework for the Indian electricity sector

Electricity Duty

In addition to the tariff set by the state ERC, state governments usually levy a tax on the sale of electricity called the ‘electricity duty’. This tax is indicated separately in electricity bills and collected by the utility on behalf of the state government. The revenue from this tax is accounted for in the state government’s budget receipts.

Electricity Regulatory Commission

ERCs are quasi-judicial bodies that frame regulations and oversee their implementation. ERCs are empowered to regulate almost every aspect of the sector: they set tariffs for generation, transmission, supply, and wheeling; issue licenses for transmission, distribution and electricity trading; and adjudicate on disputes between the various licensees and generation companies. They are also responsible for enabling and facilitating competition in the sector and protecting consumer interest.

Electricity Trader

This refers to a person who has been granted a license by the ERC to undertake trading, i.e. purchase of electricity for its resale.

Electro Static Precipitator

Electro Static Precipitator (ESP) is an equipment used in power generation plant to remove particulate matter in the exhaust gases, before it is let out to atmosphere.

Energy Banking

In the context of renewable energy, energy banking refers to an incentive for renewable energy generators under Open Access transactions where surplus generation can be notionally banked/credited with the host DISCOM after set off with consumption in the same Time of Day slot. This surplus can be offset at later during the banking period – usually one year. This is especially important for wind and solar power.

Energy Charges

The cost that the company incurs on power purchase is supposed to be recovered through the energy charge, which is the cost per unit of power consumed.

Feed-in-Tariff (FiT)

FiTs are state and technology specific preferential tariffs set by SERCs which are essentially generic regulated cost plus tariffs which ensure a certain (~16 percent) return on equity.

Feeder Separation

Usually one feeder supplies electricity to agriculture pump sets and the three phase village loads. Feeder separation involves an arrangement to separate this. It could be done physically by having separate lines or virtually, by providing three-phase supply on a rural feeder only for those hours for which pump sets are expected to operate.

Firm Capacity

Power that can be assured from the generating unit at any point in time.

Fixed Charges

Distribution companies have a certain fixed expenditure which it incurs on the creation and maintenance of basic infrastructure facilities for supplying electricity to consumers. These costs are recovered through ‘fixed charges’, also called ‘demand charges’, from the consumers.

Flexibility

The ability of a power system to respond to changes in electricity demand and supply.

Flexible Generation

The ability of the generation fleet to change its output (ramp) rapidly, start and stop with short notice, and achieve a low minimum turn-down level.

Flue Gas Desulphurisation

Flue Gas Desulphurisation (FGD) systems remove Sulphur Oxides from the exhaust gases in thermal power plants.

Forced Outage

Sometimes in a power station, some critical component might fail, or there could be a fire or a water tube leak. In such circumstances, an emergency shutdown is necessary for repair, which is called ‘Forced Outage’.

Forum of Regulators (FoR)

The FoR consists of Chairpersons of all SERCs and the CERC. It is headed by the Chairperson of the CERC. It meets every few months to share experiences and works towards the harmonisation of regulations in the power sector.

Frequency Response

The ability of generation (and responsive demand) to increase output (or reduce consumption) in response to a decline in system frequency and decrease output (or increase consumption) in response to an increase in system frequency. Primary frequency response takes place within the first few seconds following a change in frequency. Secondary frequency response (also known as regulating reserve) takes place on a timescale of minutes (or faster) following a disturbance.

Fuel Surcharge

For deviations occurring due to a difference in power procurement costs (which account for 75% of the expenses of distribution companies), it is not always practical to wait for the annual reconciliation process. Thus to aid working capital requirements and for paying off the generating company, an extra charge is levied on the consumer bill over and above the base fixed and energy charges.

Gold Plating

Cost-plus regulation tends to promote over-investment in capital assets, since the rate of return (and hence, profitability) is tied to capital investments. This is referred to as ‘gold-plating’ of investments. This is also known as the Averch-Johnson effect.

Grid Contingency

The unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker, switch or other electrical element.

Grid Parity

Consumer grid parity (socket parity) occurs when an alternative energy source (generally some RE source) can generate power at the consumer electricity tariff from the central grid. Generation grid parity occurs when alternative energy sources can generate utility scale power at a cost that is less than or equal to the cost of generation from new conventional technologies such as coal/gas etc.

Heat Rate

The rate of heat input produced by burning the fuel is measured in kcal/hour (kcal/h) while the electrical power output of the generating unit is expressed in kW. Heat rate is the ratio of this heat input to power output and is measured in kcal/kWh.

High Tension (HT) Consumers

Consumers connected to HT, that is voltage levels 11 kV or 33 kV.

High Voltage Distribution System (HVDS)

A system to reduce the length of LT network in distribution, primarily tried in India for agriculture supply. Involves installing small capacity transformers catering to 2-3 agriculture connections, in place of the current practice of high capacity transformers which supply to 15-20 pump sets spread over a larger area.

Independent Power Producers (IPP)

In 1991–92, the country launched its power sector reforms by opening its generation sector to private and global investors with a package of policy measures. These power producers are called IPPs.

Indian Electricity Grid Code (IEGC)

A set of rules and guidelines prepared by the CERC, applicable to all generators and bulk buyers who connect to the national grid.

Installed Capacity

The ‘Installed Capacity’ of a generating unit is the maximum power (usually expressed in megawatts or million watts) that it can generate.

Integrated Resource Planning

Integrated Resource Planning is a planning approach that considers both supply and demand side options to meet the requirement for a resource, while minimising the costs to the utility, government and society.

Interest During Construction

Loans are taken to fund the construction of power projects. During the construction period, interest has to be paid on the loans. However, since the plant is not functional, this interest cannot be recovered through tariff. Thus, for the duration of the plant construction and till the plant becomes operational, the interest charged is called Interest During Construction (IDC). Once the plant becomes operational, this interest is added to the capital cost of the plant and hence, becomes part of the value of the plant (asset).

Internal Rate of Return

IRR is the rate at which the investment breaks even, i.e. the discount rate at which the present value of the future cash flows equals the investment.

Levelised Cost of Energy

It is the representative per unit cost that remains constant over the life of the project.

Levelised Tariff

It is defined as the ratio of the net present value of total capital and operating costs of a plant to the net present value of the net cost of electricity generated by that plant over its operating life. The discount rate used for calculating the net present value is a crucial variable and is notified by the Central Electricity commission every six month for evaluating bids opened in that period.

Life Cycle Cost

LCC is the present value of all costs in the life of a plant. It is thus equal to the sum of the PV of annual costs, and initial cost (if any). LCC can be used to compare alternatives.

Lifeline Tariff

Households and other small consumers using very little electricity indicate a poor population. Generally, these consumers are subsidised and pay a low charge for initial consumption. this initial consumption is calculated as the bare minimum consumption or ‘lifeline consumption’. The subsidised tariff for this consumption is referred to as the ‘lifeline tariff’.

Coal Linkage

An arrangement to supply coal to an end-use plant.

Load Curve

The load curve is a graph showing the value of total active power load for a DISCOM at different points of time in a day. The load curve changes shape across different days and seasons.

Load Despatch Centres (LDCs)

They are responsible for the reliable and efficient operation of the grid.

Load Duration Curve

A graph plotted for a year, showing the number of hours that the load is equal or more than a given load (MW) value.

Load Shedding Protocol

A system devised by the regulatory commission after transparent and wide consultation to equitably share shortage of power across circles of the distribution company.

Low Tension (LT) Consumers

Consumers connected to LT, that is 415 V three phase or 240 V single phase.

Merit Order

The order in which generators are to be chosen to be scheduled to meet demand is decided based on the per unit variable cost (largely fuel cost) of generation.

Million Tonnes of Oil Equivalent (MTOE)

Is a unit used to compare different forms of energy sources.

Minimum Charge

A baseline tariff that is charged to consumers even if consumption is nil. It is generally used to recover fixed cost components for dwellings which remain uninhabited for long periods. It is also used in states with poor access to recover some amount from all consumers.

Multi Year Tariff Determination

The annual tariff filing process is often too time consuming. To ensure certainty of price and costs through better planning and to incentivise efficiency improvements, tariff determination is done for a multi-year period (usually 3-5 years). This involves projection of costs and revenues for each year within the control period.

Net Fixed Assets

Net Fixed Assets (NFA) or book value, is the reduced value (due to depreciation) of fixed assets (land, buildings, machinery etc), as entered in account books.

Net Generation

It is the total generation by the power plant excluding auxiliary consumption.

Net Load

Demand that must be met by other generation sources if all wind and solar power is consumed.

Net Metering

Net metering is a billing mechanism usually adopted for rooftop solar PV systems which allows energy banking and credit for excess solar electricity fed into the distribution grid by the project. At the end of the billing period, the consumer only has to pay for the ‘net’ electricity consumed (difference between electricity consumed from the grid and electricity fed into the grid from the solar project). If the amount of electricity fed into the grid is more than that consumed from the grid, the excess is carried forward to the next billing period.

Net Present Value

NPV is equal to the sum of the present value of all cash flows of the project less the initial investment.

Non-Tariff Income

This is the money received by an electricity company (generation, transmission, distribution) which is related to its electricity business, but is not through tariff. For example, items such as interest on staff loans and advances, sale of scrap, income from sale of tender documents or rebate on power purchase are accounted for as Non-Tariff Income by electricity companies.

Ombudsman

The system to redress consumer grievances at the state level, next to the CGRF, is the electricity Ombudsman. Grievances not resolved at the CGRF can be appealed to the Ombudsman which is set up by the SERC.

Open Access

System by which large consumers can purchase power from their choice of generator, trader or power exchange while being connected to the network of the distribution company. Non-discriminatory access to the distribution and transmission network shall be provided to such consumers to obtain supply.

Operating Reserves

Electricity generating capacity that is available to a system operator to provide for regulation (i.e., response to random movements during normal conditions), load forecasting error, forced and scheduled equipment outages, and local area protection. Other types of reserves include contingency (deployed in response to generator failures), regulating (secondary frequency response via AGC), or flexibility (reserves to address variability and uncertainty on timescales longer than regulating reserves).

Payback Period

The Payback Period is the period within which the initial investment is recovered.

Planned Outage

Periodic maintenance of each plant is typically done once a year and is called ‘Planned Outage’.

Plant Load Factor (PLF)

It is a measure of the productivity of a generating unit. For a generating unit, PLF is calculated as the ratio between the gross actual energy generation to the energy it would have generated if it were operating at its rated capacity.

Power Exchange

A transparent platform for trading of electricity, used by generators, consumers and power traders.

Power Factor

The ratio of active power to total power in an AC circuit.

Power Purchase Agreement (PPA)

A legal contract between the generator and procurer (usually distribution company) for purchase of power generated.

Prosumers

Someone who not only consumes electricity but also produces it for self-consumption through distributed systems such as solar rooftop PVs. Excess generation is fed back in to the grid.

Reactive Power

The portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment.

Reasoned Order

Orders which document objections and suggestions of all parties and which provides reasons for the decisions taken in the order.

Regulations

Rules made by regulatory authorities like Regulatory Commissions or CEA, as per its mandate under the Electricity Act, 2003.

Regulatory Asset and Carrying Cost

If in any year the regulatory commission considers the required tariff increase to be too high, it may defer part of the recovery to future years. This deferred amount then becomes an asset for the company which is recovered over time. During this period, the company is entitled to recover the carrying cost (interest charges) on this amount. Both the asset and the carrying cost is recovered from the consumers through tariff over the years. Such an asset is called a ‘regulatory asset’.

Renewable Energy Sources

Renewable Energy (RE) sources represent energy flows, which are naturally replenished at a rate that equals or exceeds its rate of use and includes low-carbon technologies such as solar, wind, hydropower, tidal, wave and ocean thermal energy, as well as renewable fuels such as biomass. India only counts Small Hydro Power (SHP) < 25 MW as part of Renewable Energy; conventional large hydropower (> 25 MW) is not part of the official definition of RE in India.

Renewable Purchase Obligation (RPO)

RPOs are targets set by SERCs, which mandate DISCOMs and other obligated entities like Open Access and captive consumers to procure a minimum fraction of their overall electricity consumption through RE.

Return on Equity

Expressed as a percentage, this is the profit or 'return' on the equity or money invested by the project developer. Equity is calculated on the gross fixed assets. Return on Equity varies between 15% to 20% in India. This return is recovered through tariff and this charge remains applicable till the project remains in operation.

Revenue Gap

The part of allowed costs by the regulator that a distribution company cannot recover through tariffs is added to the revenue requirement of the next year, to be recovered through increase in consumer tariffs. The gap between the costs and the recovered tariffs is called Revenue Gap.

Right of Way

Right of Way (RoW), is the area of the land below a transmission or distribution line, where construction of buildings and cultivation of tall trees are not permitted.

Security Deposit

The consumer uses the electricity first and pays for it later. As a security measure, the distribution company takes an advance amount from the consumer, which is known as a ‘security deposit’.

Smart Grid

It is an electricity grid with communication, automation and IT systems that enable real time monitoring and control of bi-directional power flows and information flows from points of generation to points of consumption.

Smart Meter

These meters allow for recording of electricity consumption and other power
quality metrics at a more detailed level, and further have the capability of two-way communication with the DISCOM.

Special Purpose Vehicle

It is an entity with no prior business on its books but created just for the execution and operation of a project.

Standard Bidding Guidelines

Guidelines issued by the Ministry of Power as per section 63 of the E Act which lay down a framework for competitive bidding for states power sector agencies to adopt.

Standards of Performance (SoP)

A set of 20-30 performance parameters like deviations in voltage and time taken to attend a complaint applicable to a distribution company as specified by the electricity regulator. Compensation to affected parties for non-compliance has to be paid by distribution companies and regulators can take action for consistent non-compliance.

Tariff

Tariff is the rate at which electricity is sold.

Technical Validation Session

Process before the regulatory commission where information submitted by the licensees for the tariff determination process is scrutinised, discussed and additional information is sought.

Time of the Day (ToD) Metering

Time of the Day (ToD) metering involves measuring electricity used during different times of the day, since there are different tariffs for different time slots. Peak time use attracts higher charges.

Transmission and Distribution (T&D) Loss

T&D loss is the technical loss in energy occurring between an energy source and consumers over a period of time. The T&D loss is usually expressed as a percentage of the input energy.

True-Up

Assessment of past performance of and costs incurred by licensees by the regulatory commission based on audited actuals.

Two-Part Tariff

The two part tariff for a generating plant is recovering the fixed costs and variable costs separately with two different charges.

Ultra Mega Power Projects (UMPP)

Ultra Mega Power Projects are large (4000 MW or more) projects, initiated in 2006 by the Ministry of Power. They were bid out by PFC, the nodal agency which also took on the responsibility of some of the project preparation activities such as acquiring land and securing various clearances.

Unbundling

Separation of different functions of an integrated electricity utilty like a State Electricity Board into generation, transmission and distribution.

Unscheduled Interchange (UI)

Unscheduled Interchange in a time block for a generating station or a seller is its total actual generation minus its total scheduled generation, and for a beneficiary or buyer is its total actual drawal minus its total scheduled drawal.

Variability

The changes in power demand and/or the output of a generator due to underlying fluctuations in resource or load. For renewable generation, this refers to change in generation due to wind, sunlight or water flow.

Variable Cost

It is a significant cost for fuel based power generation projects. It is variable in nature, varying with the cost of fuel and the level of generation (PLF) and is recovered through the ‘energy charge’.

Wheeling Charges

Wheeling charges account for the payments to respective licensees for use of the distribution and transmission network made by open access consumers or other licensees.

Related Publications of Prayas (Energy Group)

Amicus Populi? A public interest review of the Appellate Tribunal for Electricity, (2018)

http://www.prayaspune.org/peg/publications/item/393.html

Understanding the Electricity, Water and Agriculture Linkages, (2018)

http://www.prayaspune.org/peg/publications/item/395.html

Electricity Distribution Companies in India: Preparing for an uncertain future, (2018)

http://www.prayaspune.org/peg/publications/item/377.html

Many Sparks but Little Light: The Rhetoric and Practice of Electricity Sector Reforms in India (2017),

http://www.prayaspune.org/peg/publications/item/332.html

Bricks without Clay: Crucial data formats required for effective tariff processes, (2017)

http://www.prayaspune.org/peg/publications/item/372.html

The lesser known tariff: Fuel Surcharge levy in Indian states, (2017)

http://www.prayaspune.org/peg/publications/item/365.html

Choosing Green: The status and challenges of renewable energy based open access, (2017)

http://www.prayaspune.org/peg/publications/item/364.html

Understanding the impacts of India’s LED bulb programme, “UJALA”, (2017)

http://www.prayaspune.org/peg/publications/item/354.html

India’s Journey towards 175 GW Renewables by 2022 - A July 2017 Update, (2017)

http://www.prayaspune.org/peg/publications/item/356.html

The Price of Plenty: Insights from ‘surplus’ power in Indian States, (2017)

http://www.prayaspune.org/peg/publications/item/335.html

In the Name of Competition: The annals of ‘cost-plus competition’ in the electricity sector in Mumbai, (2017)

http://www.prayaspune.org/peg/publications/item/333.html

Residential Electricity Consumption in India: What do we know? (2016)

http://www.prayaspune.org/peg/publications/item/331.html

Coal Block Allocations: Opportunity Lost, Chaos Gained?, (2015)

http://www.prayaspune.org/peg/publications/item/312.html

Demanding Electricity Service: A Guide for the Community Activist, (2015)

http://www.prayaspune.org/peg/publications/item/300.html

How Much Energy Do We Need: Towards End-Use Based Estimation For Decent Living, (2015)

http://www.prayaspune.org/peg/publications/item/300.html

Black and Dirty: the real challenges facing India’s coal sector, (2013)

http://www.prayaspune.org/peg/publications/item/191.html

10 Questions to ask about Electricity Tariffs, Prayas (Energy Group) and WRI, (2014)

http://www.prayaspune.org/peg/publications/item/272.html

10 Questions To Ask About Integrated Resources Planning, Prayas (Energy Group) and WRI, (2014)

http://www.prayaspune.org/peg/publications/item/274.html

Consumer’s Guide for Electricity Service - Information on consumer related rules and regulations, (2010)

http://www.prayaspune.org/peg/publications/item/86.html

Awareness and Action for Better Electricity Service - An agenda for the community, (2008)

http://www.prayaspune.org/peg/publications/item/64.html

Alternative Power Planning, Prayas (Energy Group) and Kalpavriskh, (2007)

http://www.prayaspune.org/peg/publications/item/63.html