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Renewable Energy in India: Economics and Market Dynamics
 2021935949, 9789353887810

Table of contents :
Cover
Contents
List of Illustrations
List of Abbreviations
Foreword
Preface
Acknowledgements
Chapter 1
Renewable in India
Chapter 2 Structural Reforms in Power Sector
Chapter 3 Policies Supporting Renewable
Chapter 4 Distributed Energy Resources
Chapter 5 Renewable Energy Pricing in India
Chapter 6 Renewable Purchase Obligation
Chapter 7 Renewable Energy Certificate (REC)
Chapter 8 Intermittent Renewable
Chapter 9 Market Design for Renewable Energy
Chapter 10 Renewable Policy Introspection
About the Authors
Index

Citation preview

RENEWABLE ENERGY IN INDIA Economics and Market Dynamics

Pramod Deo Sushanta K. Chatterjee Shrikant Modak

SAGE was founded in 1965 by Sara Miller McCune to support the dissemination of usable knowledge by publishing innovative and high-quality research and teaching content. Today, we publish over 900 journals, including those of more than 400 learned societies, more than 800 new books per year, and a growing range of library products including archives, data, case studies, reports, and video. SAGE remains majority-owned by our founder, and after Sara’s lifetime will become owned by a charitable trust that secures our continued independence. Los Angeles | London | New Delhi | Singapore | Washington DC | Melbourne

Renewable Energy in India

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Renewable Energy in India Economics and Market Dynamics

Pramod Deo Sushanta K. Chatterjee Shrikant Modak

Copyright © Pramod Deo, Sushanta K. Chatterjee and Shrikant Modak, 2021 All rights reserved. No part of this book may be reproduced or utilized in any form or by any means, electronic or mechanical, including photocopying, recording, or by any information storage or retrieval system, without permission in writing from the publisher. First published in 2021 by SAGE Publications India Pvt Ltd B1/I-1 Mohan Cooperative Industrial Area Mathura Road, New Delhi 110 044, India www.sagepub.in SAGE Publications Inc 2455 Teller Road Thousand Oaks, California 91320, USA SAGE Publications Ltd 1 Oliver’s Yard, 55 City Road London EC1Y 1SP, United Kingdom SAGE Publications Asia-Pacific Pte Ltd 18 Cross Street #10-10/11/12 China Square Central Singapore 048423 Published by Vivek Mehra for SAGE Publications India Pvt Ltd. Typeset in 10/12.5 pt ITC Stone Serif by AG Infographics, Delhi. Library of Congress Control Number: 2021935949

ISBN: 978-93-5388-781-0 (HB) SAGE Team: Rajesh Dey, Syed Husain Naqvi, Madhurima Thapa and Kanika Mathur Disclaimer: The views contained in the book are the personal views of their respective authors and do not, in any way, reflect their official views. These are to be considered solely in their personal capacities.

Contents

List of Illustrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii List of Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix Foreword by Kirit Parikh . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiii Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xvii Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xxi Chapter 1. Renewable in India: In the Context of Evolution of Power Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Chapter 2. Structural Reforms in Power Sector: Implication for Renewable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Chapter 3. Policies Supporting Renewable: Aid to Market Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Chapter 4. Distributed Energy Resources: Business Models and Market Dynamics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Chapter 5. Renewable Energy Pricing in India: What Is Missing? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Chapter 6. Renewable Purchase Obligation: Does It Need a Revisit as Instrument for Market Creation? . . . . . . . . . . . . . . . . 106

Chapter 7. Renewable Energy Certificate (REC): Has It Outlived Its Life as Market-based Mechanism? . . . . . . . . . . . . . . 138 Chapter 8. Intermittent Renewable: How to Enable Participation in Market? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157 Chapter 9. Market Design for Renewable Energy: Right Design, A Missing Link in India . . . . . . . . . . . . . . . . . . . . . . . 176 Chapter 10. Renewable Policy Introspection: Rethink and Move in the Right Direction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198 About the Authors����������������������������������������������������������������������������225 Index��������������������������������������������������������������������������������������������������228

vi  Renewable Energy in India

List of Illustrations

List of Figures 8.1 Tamil Nadu State Demand versus Wind Generation (22 August 2017)—Maximum Wind Generation Day 159 8.2 Demand in Gujarat on 22 May 2017, along with How This Was Met from Various Sources of Generation Available—Maximum Wind Variation Day  160 9.1 All-India Demand and Net Demand of a Typical Day (in 2021–2022)  181 9.2 Short-term Trading Price Trends  184 9.3 Share of Market Segments in Total Electricity Generation, 2019–2020  185 9.4 Price Variation in Power Exchange during a Typical Day  186 9.5 Price Variation in Power Exchange during a Week  187 9.6 Price Variation in Power Exchange during a Month 188

List of Tables 4.1 The Year-wise Cumulative Solar Power Rooftop PV Installations (2015 to 2018 February)  50

6.1 Long-term Growth Trajectory of Renewable Purchase Obligations for Solar and Non-solar as Determined by the Ministry of Power  114 6.2 State-wise Renewable Purchase Obligations for Solar and Non-solar as per MNRE’s National Portal for RPO  115 7.1 RE Generators Registered (No. of Projects and Capacity in MW as on 31 March 2018)  150 7.2 Demand and Supply of REC (2012–2013 to 2018–2019) 151 10.1 Prices of Solar Projects Discovered through Bidding 201

List of Appendices 5A State-wise Latest Wind and Solar Tariff Rates  81 5B Bid Tariff (Wind)  87 5C Bid Tariff (Solar)  93 6A.1 Targets of Renewable Purchase Obligation Set by State Electricity Regulatory Commissions from 2010–2011 to 2019–2020 (in %)  124 6A.2 Compliance of Renewable Purchase Obligation by the Utilities from 2010–2011 to 2013–2014  126 6B State-wise RPO Target (FY 2016–2017 to FY 2020–2021) and RPO Compliance (FY 2016–2017 to FY 2018–19)  128

viii  Renewable Energy in India

List of Abbreviations

AC AGC APERC APPC AS CASE CDM CEA CERC CFD DC DISCOM DNES DRE DSM DT EA EE eRA ERC FERC FIT

Alternating current Automatic generation control Andhra Pradesh Electricity Regulatory Commission Average power purchase cost Ancillary services Commission for Additional Sources of Energy Clean Development Mechanism Central Electricity Authority Central Electricity Regulatory Commission Contract for difference Direct current Distribution company Department of Non-conventional Energy Sources Distributed renewable energy Deviation Settlement Mechanism Distribution transformer Electricity Act Energy entrepreneurs e-Reverse auction Electricity Regulatory Commission Federal Energy Regulatory Commission Feed-in tariff

FOR Forum of Regulators FY Financial year GOI Government of India GRPV Grid-connected rooftop photovoltaic IEGC Indian Electricity Grid Code IEX Indian Energy Exchange INDC Intended Nationally Determined Contributions IPP Independent power producer ISGS Inter State Generating Station ISO Independent system operator ISTS Inter-State Transmission System LMP Locational marginal price LRMC Long-run marginal cost MBED Market Based Economic Dispatch MGP Mera Gao Power MNES Ministry of Non-conventional Energy Sources MNRE Ministry of New and Renewable Energy MW Megawatt NAPCC National Action Plan for Climate Change NEM Net Metering Regulation NETA New Electricity Trading Arrangement NFFO Non-Fossil Fuel Obligation NLDC National Load Dispatch Centre O&M Operation and maintenance P2P Peer-to-peer PAYG Pay-as-you-go PPA Power purchase agreement PTC Production tax credit PURPA Public Utility Regulatory Policies Act PV Photovoltaic PX Power exchange(s) QCA Qualified Coordinating Agency RA Reverse auction RE Renewable energy REC Renewable energy certificate REMC Renewable Energy Management Centre RFS Request for selection RLDC Regional load despatch centre x  Renewable Energy in India

RO ROC RPC RPI RPO RPS RRAS RTM RTO SEB SECI SERC SLDC SRMC TAC TAM TERI UP UPNEDA UT

Renewables Obligation Renewables Obligation Certificate Regional Power Committee Retail price index Renewable purchase obligation Renewable portfolio standard Reserves Regulation Ancillary Services Real-time market Regional transmission organization State Electricity Board Solar Energy Corporation of India State Electricity Regulatory Commission State load dispatch centre Short-run marginal cost Transmission access charge Term Ahead Market The Energy and Resources Institute Uttar Pradesh Uttar Pradesh New and Renewable Energy Development Agency Union territory

List of Abbreviations  xi

Foreword

How to Promote Renewable Power The importance of solar energy and other forms of renewable energy was recognized in India more than a decade ago. Its promotion began initially with policies to promote wind power, by providing subsidies on capital costs, accelerated tax write-offs and by launching of the National Solar Mission in 2010—targeting a solar capacity of 20,000 megawatts (MW) by 2022. This target was then further increased by Prime Minister Narendra Modi to 175,000 MW by 2022. The promotion of renewable power faces many difficulties, though not insurmountable. In 2010, the cost of solar power was four times that of coal-based power plant. Also, solar and wind power, being subject to vagaries of nature, are not available on demand. Since their generation is intermittent with a wide variation in their availability—between 15 and 30 per cent of the capacity, in comparison to over 80 per cent for coal-based plants—it creates difficulties in their acceptance by the power project developers as well as by the power distribution agencies. Although the cost of installing a solar photovoltaic plant has fallen dramatically over time, and the levelized cost of solar power is now almost comparable to that of coal power, its intermittent nature requires balancing power with corresponding

modifications in the grid transmission infrastructure. This calls for additional expenses. Thus, these costs have to be considered when comparing renewable power with conventional power. India has tried several approaches in promoting solar power. It has provided assured feed-in tariffs to solar power developers, and it has mandated power distribution companies to purchase a stipulated percentage of power from renewable power generators. Moreover, it has created tradable instruments like renewable energy certificates to enable mandated entities in meeting their renewable portfolio obligations. It has also waived all transmission charges on the interstate movement of renewable power. This has been done to facilitate the purchase of renewable power from the states with higher renewable power potential to those with lower potential. These measures have had their own logic, but they also had problems with them. This book, written jointly by the former chairman of the Central Electricity Regulatory Commission, an expert in infrastructure economics, co-authors with specialization in management and finance, who have teaching experience in various academic, research and training institutions, and an academic turned journalist with expertise in energy economics, discusses the issues pertaining to pricing of renewable energy and its commercialization in India. The book lucidly explores the rationale behind the various government policies in India adopted for commercializing renewable power generation nationally. It then compares the Indian experience with the international experience in this field. The problems faced in the commercialization of this form of energy and possible solutions have been thoroughly discussed. The chapters in the book are logically sequenced to address the issues involved and to address the problems raised by the steep fall in the costs of renewable generation. Finally, it provides the way forward suggesting the ways in which these problems could be overcome. The book provides a significantly different perspective than what is normally available in books dealing with renewable xiv  Renewable Energy in India

technology and economics of it. It is largely focused on issues in pricing renewable power appropriately, evolving market mechanisms to commercialize it, in regulating it and in absorbing it into the grid. The issues involved in promoting distributed power through micro-grids have also been considered separately. I learnt quite a few things by reading this book, and I recommend it to all those who are interested in promoting renewable power in the country and the world. It is a very useful book not just for India but also for any country interested in accelerating the development of renewable power. Kirit Parikh Chairman, Integrated Research and Action for Development (IRADe) Former Member, Planning Commission New Delhi 15 December 2020

Foreword  xv

Preface

It is indeed gratifying to discover, after more than three decades as professional energy specialists, that many of the assumptions on which we had worked were now becoming a reality. At our baptism in the power sector during the 1980s/1990s, we could not have imagined that India would be soon crossing the mark of 100 GW of green energy. Energy self-sufficiency was identified as the major driver for new and renewable energy in the country in the wake of the two oil shocks of the 1970s. The sudden increase in the price of oil, the uncertainties associated with its supply and the adverse impact on the balance of payments position led to the establishment of the Commission for Additional Sources of Energy (CASE) in the Department of Science & Technology in March 1981. In 1982, a new department, that is, the Department of Non-conventional Energy Sources (DNES), which incorporated CASE, was created in the then Ministry of Energy with the responsibility of formulating policies and their implementation, programmes for the development of new and renewable energy, apart from coordinating and intensifying R&D in the sector. In 1992, DNES became the Ministry of Non-conventional Energy Sources. In October 2006, the Ministry was re-christened as the Ministry of New and Renewable Energy.

The journey of promotion of renewable has continued since then. On the policy front, the Ministry of Power and the Ministry of New and Renewable Energy and, on the regulatory front, the Regulatory Commissions have been taking steps to promote renewable energy. But electricity, and more so the renewable, being an intensely political economy issue, the gap between vision and reality is a norm rather than an exception in this segment of the economy. Some of us lived through and grew with this experience, and it is this reality that gave us the motivation to write this book. Policymaking is a long-drawn and arduous process, and not necessarily always dictated by the doctrines of economics, even if the subject matter demands consideration of such principles. Social and political expediency often outweighs economic considerations. It is this dilemma that we have tried to capture through the seams of the book. We have discussed policy and regulatory initiatives but, at the same time, have endeavoured to bring in a future-looking perspective by blending the academic, research and professional experience of us authors. The focus has been on economics of renewable, especially the distinctiveness of this form of generation in terms of variability, followed by its supply and pricing principles and market dynamics. These aspects have been analysed in the backdrop of various theories before venturing into practices and eventually into what we consider as the missing approach, especially on pricing and market design of renewable in India. This perspective, we believe, would remain relevant not only for an academician/researcher but also for hardcore professionals and practitioners in this field. Varied experiences of the authors, ranging from spearheading central-level energy management centre, state energy development agency, regulatory commissions at the state and central levels; key roles played in drafting new electricity law, national electricity policy, tariff policy, rules and regulations, and developing a new market design with a focus on the integration of renewable and an incisive analysis of an economist and columnist bring a distinctive flavour to the discourses in the book. xviii  Renewable Energy in India

Global developments are the overarching context for an exercise in which our national performance is assessed. To appreciate its consequences, what we require at home is a dispassionate debate that rises above competitive politics. We are in debt to numerous energy experts whom we earlier used to meet physically in workshops, seminars and conferences, and for the last 8 months virtually for their contrarian viewpoints, which helped us to develop a holistic approach. Our publishers have been very patient as the fate of the book was linked to the twists and turns in our own lives. We hope that their forbearance is rewarded.

Preface  xix

Acknowledgements

We express our gratitude to the policymakers, regulators, energy experts, academicians and researchers who helped shape our thought process. But for their intellectual engagement, we could not have reached this stage of our professional life and penned a book on a specialized subject like this. Our special thanks to the colleagues who contributed in data compilation, especially Mr Rajashekhar, Mr Ravi and Mr Suresh, to name a few. Mr Arora and Ms Boby also merit mention for their support in text formatting and typing. Last but not the least is the unflinching support of our family members—Neelam, Nandini, Tanusree, Tannishtha, Jyoti, Mrinal and Sudeep, who stood by us through our arduous journey and continued to inspire us, to make sure that our idea fruitions into a meaningful manuscript. They have been a witness to the trials and tribulations that we have gone through, and they have provided us with sustenance in our containment. We take this opportunity to record our sincere thanks to all those who helped us, directly or indirectly, in making this book a reality.

1

Renewable in India In the Context of Evolution of Power Sector

Introduction The central theme of the book is the economics of renewable (wind and solar to be specific) with a focus on pricing and market dynamics, given the special natural of its production, and this idea runs through the seams of all chapters. To start with, this chapter sets out the context by presenting an overview of the electricity industry in India, with a special reference to renewable energy (RE), and discusses the electricity reforms in other parts of the world. It also traces the technological and structural evolution of the sector, with a focus on tariff, a central piece of electricity regulation. Demand for power is central to all planning processes in any power system. Generation and transmission are planned to make sure that the power consumption need of consumers is met at all times. Demand pattern varies by day, across seasons, depending on various factors such as weather, festivals and economic activities. The challenge of power system planning and operation is to match generation to follow this curve, often

termed as the load duration curve. Generation planning is done on a long-term time horizon and a portfolio of different fuel source-based generation is created to cater to the power requirements at different time intervals. Thus, we have coal-based generation capacity to meet base load, hydro to meet peak load and gas-based capacity to address the flexibility requirement. To this portfolio, there is a growing trend of adding RE resources, largely driven by environmental concerns. For generation planning, generally peak load is taken as a reference. For instance, the peak demand in India during Financial Year (FY) 2019–2020 was 184 GW. Against this requirement, the country had a total installed generation capacity of 370 GW, comprising 199 GW of coal-based generation capacity, 6.6 GW of lignite, 25 GW of gas-based, 46 GW of hydro, 87 GW (as on 29 February 2020) renewable, 6.8 GW of nuclear source-based generation capacity.1 Coal is an exhaustible source, gas supply in the country is limited and import is expensive and the hydro project costs are quite high, at least in the initial years. Energy security is therefore a big concern more so for a developing country like India. Given these realities and also driven by environmental concerns, India has of late put a lot of emphasis on adding renewable generation capacity on a big scale.

Renewable Revolution India has been at the forefront of international efforts at harnessing RE for decades now. We have one of the largest and most ambitious programmes in this field in the world. More than 86,759 megawatt (MW)2 of power-generating capacity based on RE sources has been installed until February 2020. This constitutes over 23.48 per cent of the total installed power capacity of the country, most of which comes from private investments. With wind power capacity of 37,669.25 MW, 3 India ranks 4th4 among the major global countries engaged in the

2  Renewable Energy in India

commercialization of wind energy. It is also engaged in expanding its small hydroelectric generation, which is particularly suitable for remote hilly regions and the north-eastern states because of their sizeable hydropower potential. The Ministry of New and Renewable Energy (MNRE) in India is in charge of projects up to 25 MW. Around 4,683 MW5 of small hydro capacity has been installed already until February 2020. Besides, as the leading sugarcane producer in the world, the country has been engaged in implementing the largest bagasse-based co-generation power programme in its sugar mills. In 2015, the Indian government announced an ambitious target of 175 GW for RE capacity to be added to the grid by 2022. It meant that the annual RE capacity in the country would have to grow at a rate of 25 per cent in a short period of time available, as against the recent annual capacity growth rates achieved by all grid-based electricity generation of about 6 per cent.6 In 2018, India had the third largest power grid in the world, with a gross capacity of 344 GW. The RE constituted only 7.6 per cent of it. But with the induction of the projected magnitude of fresh RE capacity in the national system, there would have to be a quantum jump in this share to 20 per cent of the country’s total power capacity by 2022. For this magnitude of achievement to sustain, it is important to mobilize investments both in RE capacity and supporting infrastructure, which would be a herculean task in the limited time available. However, even if this seems difficult, the emphasis on accelerated RE capacity addition in the system is expected to persist over a decade to come. To achieve this, investments in supporting infrastructure growth would have to keep in sync with the former. India’s initiatives in RE reflect what has been happening elsewhere in the world. For example, in Europe, many countries have been making conscious efforts to promote greater utilization of RE to reduce greenhouse gas emissions. In Austria and Finland, electricity from RE constitutes over 10 per cent of their total energy production and this figure is even higher

Renewable in India  3

in Denmark. The UK, too, is having a robust RE-based power generation programme. In India, when the Standing Committee of Parliament was examining the Draft Electricity Bill, the Ministry of Nonconventional Energy Sources (MNES; presently MNRE) had suggested the incorporation of enabling provisions in the Bill with a view to promoting the development of non-conventional energy-based power for the grid. The suggestions included the mandate for the Central Electricity Regulatory Commission (CERC) to frame guidelines on ‘preferential’ prices for renewables by taking into account the avoided cost of negative externalities associated with fossil fuel-based generation. The need for promotional measures, such as banking, wheeling and third-party sales, was also emphasized. There were, at the same time, suggestions from some other stakeholders to prescribe specific provision in the Bill for a minimum energy procurement requirement (say, 10%) from RE sources.7

Issues However, the Electricity Act, 2003 (EA, 2003)8 did not quite incorporate these provisions as explicitly as the MNRE would have preferred. But what it did was to specify that the State Electricity Regulatory Commission (SERC) must …promote co-generation and generation of electricity from renewable energy sources by providing suitable measures for connectivity with the grid and sale of electricity to any person, and also specify, for the purchase of electricity from such source, a percentage of the total consumption of electricity in the area of a distribution licensee.

The Act thus left the modalities of carrying out the task to the ground-level assessment and professional judgement of the concerned commissions. The Act also provided for the promotion of renewable as one of the guiding principles for tariff determination by electricity regulators.

4  Renewable Energy in India

While some SERCs had already taken initiatives in this direction, CERC, through its successive regulations, provided the basis for the market-based mechanisms to begin to develop. This, in turn, helped in facilitating the processes at different times across India. This has been discussed in this book in the subsequent chapters. While the promotion of co-generation and generation of electricity from renewables guided the tariff regulation by the SERCs—to the extent that they had a bearing on the average cost of power generation and distribution in the system—both conventional and renewable power generators were able to link their generating units to the electricity grid by meeting the technical standards set for them. This aspect has been covered in the later part of the book against the background of international experience. It has been more than a decade since the EA was promulgated in 2003. Yet the question ‘What role should the commissions play in promoting RE systems in their states’ has remained relevant. Should they encourage the guaranteed export of surplus power when produced from these technologies at feed-in rates to the national grid? And, if so, what should these rates be? Looking at it differently, one may ask whether there is still a justification in giving preferential treatment to RE technologies over time-tested conventional power generation technologies for supplying electricity to the grids? Has there been an international experience that can provide insights into the various issues relating to the promotion of RE technologies? And whether there is anything that India can gain from the experience in other countries. There are other issues that need to be addressed as well. First, the age-old environmental debate regarding the pricing of electricity from conventional power plants, which ignores the external costs associated with producing power from these sources. This indeed goes against the spirit of the Act, which requires fairness in the treatment of costs, irrespective of the source of generation. Second, though the state commissions

Renewable in India  5

are free under the EA, 2003, to incorporate a surcharge for cross-subsidies in addition to the wheeling charges, the subsidies referred to are on account of the differential pricing at the consumer level. But nothing is mentioned in the Act about how to tackle any increase in average electricity costs that may take place due to the promotion of RE-based power as a consequence of states’ RE programmes. Apparently, it seems that this increase is meant to be a ‘pass-through’ in the determination of average tariffs to consumers. This means that consumers must pay for these programmes. Finally, how does one reconcile with competition in the electricity sector due to preferential treatment for predetermined sources of energy? Of course, no Act can provide perfect answers to all possible contingencies. But, as things stand, the EA, 2003, provided a novel legal setting that has spurred developments in the Indian power industry for over a decade now. The Act itself had been a product of considerable deliberations and debate, both inside and outside the Parliament, before it was cleared. In fact, in many ways, it has reflected both the changed global view and the Indian perception about the nature of the power industry. As a result, new initiatives have ushered towards creating a market-friendly structure.

Technological and Structural Evolution of the Sector A peek into the history of electricity reveals how technological developments—with respect to transmission and generation— have triggered the structural evolution of the power industry. The first-ever power system, installed in the USA by Thomas Alva Edison in 1880, was powered by direct current (DC) generators run by the steam engine. It pumped electricity into distribution system lighting 400 bulbs of 83 watts at a time.9 This technology soon proliferated worldwide, when hundreds of entrepreneurs replicated it throughout the major cities in the world. One common feature of these systems—against the background of high losses suffered while transmitting low-voltage

6  Renewable Energy in India

DC—was that it required the stationing of generation units close to the loads that were being served. With the development of the transformers, the alternating current (AC) became the dominant technology in the transmission of power.10 With the continuing evolution of transmission technology into high-voltage transmission lines and the corresponding breakthrough in generation technology—with the replacement of steam engines by steam turbines—it became possible to produce and transfer bulk power to load centres located at considerable distances from the power-generating plants. With every rise in the transmission voltage and turbine size, power networks across the world began to increasingly wear a look of natural monopolies—especially public utilities—where average costs were falling with rising outputs. The markets, on the other hand, were often not large enough to absorb their supply of electricity. In the post-1930s, the focus with respect to technological development in the power sector was on scaling up the size of conventional power plants. The economies of scale, due to higher thermal efficiency, as well as lower specific investments in power stations, gave rise to a trend where power plant size kept on increasing with each installation. For example, the most efficient power plant size in the 1930s was 60 MW. It rose to 180 MW during the 1940s and, by the 1980s, it reached 1,000 MW.11 Similarly, the development of new converters, based on thyristor technology, made high-voltage DC lines a very promising option for the transmission of power over long distances. But, above all, further improvements in AC high-voltage transmission links had the most significant influence on the structure of modern power systems. They made the interconnection of the regional system feasible.12 With these ongoing developments, it became almost impossible for smaller utilities to compete on their own in the power industry, and this gave rise to vertically integrated monopolies having centralized control over the entire electricity supply chain. This called for greater regulation of power utilities.

Renewable in India  7

In countries where these utilities were privately owned, it meant closer vigilance over their operations in the larger public interest. Where they were brought under public ownership, the control was more direct. Either way, profits became the regulatory focus, giving rise to cost-plus rate-of-return approach. This has survived all these years and continues to hold sway even now with regulatory authorities in many countries for setting tariffs for consumers. With this change, it also became obligatory on the part of power utilities to supply electricity to all classes of consumers at predetermined tariffs—universal service obligation.

Evolution of Electricity Legislation in India The electricity legislation that has evolved in India over the years, in many ways, reflects these global trends. For example, as explained earlier, in the early 20th century, transmission and generation technologies were still in the infancy stage; power generation in that era was possible only through small generating sets. Understandably, in India too, the sector was made up of small generating companies, owning 30–60 MW units and supplying mostly to urban areas. The Indian EA, 1910, came up against this background. Its purpose was to regulate small licensees and to protect consumers. By 1948, there were significant advances in power generation technology, giving rise to economies of scale in power generation. This, together with the advances in transmission technology, made it possible to transmit power at high voltages over long distances. The result was the establishment of typical state-owned, centralized power generation, transmission and distribution utilities in the form of State Electricity Board (SEB) in the country. In fact, the Electricity (Supply) Act, 1948, was specifically meant to constitute and regulate the activities of these utilities. This vertical structure of power utilities came into question worldwide on grounds of efficiency, during the 1990s. India too was affected by this global concern for efficiency, which gave rise to electricity reforms. 8  Renewable Energy in India

Globally, the first country to start off on the reforms path in the power sector was Chile in 1982. But it was the reforms in Britain, with its EA of 1983, that abolished the legal monopoly of the Central Electricity Generating Board in England and Wales that caught the fancy of reformers all over the world. To begin with, independent generators were allowed to wheel electricity directly to retail customers. Subsequently, there were changes in the approach, based on the experiences gathered from the initial implementation of the Act. However, all of these were in the direction of increasing competition in the power grid of the region. Emulating England, several countries followed suit and instituted reforms with modifications in their own power industry in the 1990s. The Norwegian Parliament passed a new Energy Act in 1990; the Swedish Parliament revised its EA of 1902 in 1995; and, in 1993, the Council of Australian Governments accepted the federal proposal put forth in 1991 to create a National Electricity Market. Even countries such as Israel and Argentina went ahead with instituting electricity reforms. A common aspect of each of these was to create competition, in varying degrees, in their respective electricity markets. The Indian Legislation—known as the EA, 2003—came about against this background of international legislation in the power sector. At a macro level, the central feature of this law has been unbundling of the power sector into its constituent segments; and, at a micro level, altering operational terms in a manner that would be conducive to greater competition.

Power Tariff: A Central Piece of Electricity Regulation The central aspect of all electricity regulation, wherever there have been vertically integrated power utilities, has been the tariffs. Before the Electricity Regulatory Commissions (ERCs) Act, 1998, came into force in India, five sets of norms for setting tariffs were in force. One specified by Schedule VI of the Electricity (Supply) Act, 1948, was for determining retail tariffs

Renewable in India  9

of licensees under the Indian Electricity Act, 1910. The second part, Section 59 of the Electricity (Supply) Act, 1948, pertained to the retail tariffs to be set by the SEBs. The third, specified by the central government under Section 43 A(2) of the Electricity (Supply) Act, 1948, was meant for determining the bulk tariffs to be charged by the central utilities. The fourth, under Section 43 A(2), was again for bulk tariffs, for state utilities. And the fifth (Section 41 of the 1948 Act) was for the transmission tariffs to be charged by the utility, for transmitting power to and across states, through its network. Despite differences, there has been a fair degree of commonality in all five sets of norms.13 Interestingly, all the Acts have focused on tariffs. In this book as well, we have discussed tariffs; but from a perspective of renewable power technologies. In many ways, the norms reflect the evolution of India’s power sector over the years. When central power stations came up in the 1980s against the backdrop of failing health of SEBs and the inability of states to finance the expansion of power generation from their own funds, it became necessary to put in place tariff norms for the supply of power by these stations to SEBs. In the wake of the resource crunch in the 1990s, it became even more difficult to finance plans for the expansion of the power sector with public funds; generation was opened up to independent power producers (IPPs) to plug the investment gap. This necessitated the setting up of tariff norms for the bulk supply of electricity by these producers. Interestingly, this was also the backdrop against which alternative energy options began to be more seriously considered for the supply of electricity to the grid. Moreover, when it became clear that the IPP policy was unsustainable due to poor financial health of SEBs—caused by years of political manipulation of electricity pricing, theft and inefficiencies—the ERCs Act, 1998, was brought in to ‘stem the rot’. With this, SERCs assumed the function of approving electricity tariffs based on the principles laid down in this Act. In final admission of the fact that the piecemeal legislation was not enough to grapple with India’s power sector problems, a 10  Renewable Energy in India

comprehensive EA, 2003, was passed by the Parliament. This Act, similar to the legislations in other countries, sets out the basic ground for the unbundling of the entire power industry. In fact, it attempts to create environment conducive to competition on the supply side of the industry. It is thus based on the premise that the industry’s regulation is appropriate only in segments where a competitive market is not feasible. The Act reflects the latest global technological and structural trends in the reorganization of the sector. Conventional technologies having matured are no longer able to demonstrate economies of scale in relation to market size. The plant sizes of conventional power plants have stabilized globally. At a different level, distributed technologies, such as combined cycle gas turbines, have been introduced that generate power as economically as conventional power plants. In specific cases, even RE technologies have reached a stage where they are economically competitive with conventional power plants. All these developments have taken place against the background of expanding worldwide electricity consumption. One major advantage of RE technologies in comparison with the conventional technologies is that they require smaller investments in generating plants than the latter. Moreover, the time taken for erecting these units is in months as opposed to several years in the case of conventional technologies. This means that size is no longer an issue as far as electricity generation is concerned, and this segment of the power supply chain is now most amenable to competition. Although this may not be true for the transmission and distribution segments of the industry, it has been observed that by separating dispatch of power from the ownership of wires and by providing open access to all, it is possible to create competition in wholesale and retail segment of the industry. Significantly, the operational structure of the vertically integrated SEBs centralized and internalized all transactions between different segments of the industry. In contrast, the provision for unbundling in the EA, 2003, by separating and

Renewable in India  11

segmenting various parts of the industry, has begun to demerge and change the commercial interface between these segments and their parts. It has also required different rules for pricing services in demerged segments. This means that the renewable power producers, just as others, now have to operate under altogether different business environments than before. Yet, in the transitory phase, the interface of these producers with unbundled utilities has required regulatory oversight for a variety of reasons. The regulation in the structurally changed sector in the future will continue to be based on the following principle: ‘…regulate only those segments which by their nature are not amenable to competition.’14 Here, regulators so far have had to act as ‘surrogate’ markets for enforcing the requisite economic discipline in the absence of markets. One of the main issues, in so far as RE technologies are concerned, is that regulators have had to deal with aspects of the markets that could lead to market failures, hampering the commercial evolution of these technologies. At a different level, regulators have strived to refrain from resorting to the cost-of-service regulation in sectors that are competitive. But this has not been easy. Whereas in sectors that require price regulation (or support), prices have had to be set at sufficiently high levels to enable power producers to earn enough to meet their investment needs, but low enough to spur them to improve their efficiency in order to maintain profitability. To achieve this, the regulatory bodies have had to strive towards knowing the power industry as well as the industry itself in order to enforce the regulations. The regulation of tariffs of electricity from renewable sources has continued to be of importance since the EA, 2003, came into being. However, the direction of regulation has taken a decisive turn in recent years. The focus has changed gradually towards imparting greater market orientation to this sector. There has been a growing stress on evolving a market in this sector in a manner that the overall value of green power is 12  Renewable Energy in India

market determined, though within the limits to be set by the regulatory authority. However, the question as to how these limits are to be set is still of relevance.

Chapter Conclusion Renewable has taken centre stage in the discussion on the power sector in India. The ambitious target of renewable capacity addition would require the mobilization of investments both in RE capacity and in the supporting infrastructure—a herculean task indeed in the limited available time (target of 175 GW by 2022). However, even if this seems difficult, the emphasis on accelerated RE capacity addition in the system is expected to persist over a decade to come. It must be emphasized that pricing of electricity is central to the efficient functioning of any industry, and much of the regulatory process in India has been devoted to addressing this seemingly complex issue, since the EA, 2003, came into operation. However, this book focuses on pricing in those segments of renewable electricity generation, namely solar and wind energy, which produce electricity on mass marketable scale. Within the renewable technology sector, these generation technologies have proved to be the most successful of all the available technologies in mass commercialization worldwide. Hence, much of the regulatory effort has been on supporting and facilitating the induction of these technologies into the national market defined by the state and the national grids. Having set the context, the focus in the next chapter is on how structural reforms have shaped the electricity industry and, in turn, impacted the commercial viability of renewable.

Notes 1. http://cea.nic.in/reports/monthly/executivesummary/2020/ exe_summary-03.pdf (accessed on 8 February 2021). 2. Ibid., 4. 3. Ibid., 14.

Renewable in India  13

4. https://www.power-technology.com/features/wind-energy-bycountry/ (accessed on 4 December 2019). 5. http://cea.nic.in/reports/monthly/executivesummary/2020/ exe_summary-02.pdf (accessed on 9 May 2019), 14. 6. Rahul Tongia and Samantha Gross, ‘Working to Turn Ambition into Reality, the Politics and Economics of India’s Turn to Renewable Power’ (Working Paper No. 4, Brookings, Washington, DC, 2018), 4. 7. Standing Committee on Energy, Thirteenth Lok Sabha, ‘Ministry of Power Thirty-first Report, the Electricity Bill, 2001’ (2002). Available at https://eparlib.nic.in/bitstream/123456789/63654/1/13_ Energy_31.pdf (accessed on 18 November 2020). 8. https://powermin.nic.in/sites/default/files/uploads/The%20 Electricity%20Act_2003.pdf (accessed on 18 November 2020). 9. Ackermann, Thomas (First Draft 1999), Distributed Power Generation in a De-regulated market Environment, Part I, Working Paper, Royal Institute of Technology, Stockholm, Sweden. pp 14. 10. Ackermann, Thomas (2004), Distributed Resources in a Re-regulated Market, Doctoral Thesis. KTH Electrical Engineering, Stockholm, Sweden. pp 54. 11. Ackermann, Thomas (First Draft 1999), Distributed Power Generation in a De-regulated Market Environment, Part 1, Working Paper, Royal Institute of Technology, Stockholm, Sweden, pp 16. 12. Ackermann, Thomas (First Draft 1999), Distributed Power Generation in a De-regulated Market Environment, Part 1, Working Paper, Royal Institute of Technology, Stockholm, Sweden, pp 16. 13. S. S. Ahluwalia and Gaurav Bhatiani, ‘Tariff Setting in the Electric Power Sector’, in The Indian Case Study in Regulation in Infrastructure Services: Progress and the Way Forward, ed., S. K. Sarkar and Kaushik Deb (New Delhi: TERI, 2001), 67–104. 14. Ibid.

14  Renewable Energy in India

2

Structural Reforms in Power Sector Implication for Renewable

Introduction The electricity industry structure has evolved over the years and has witnessed significant changes, especially during the last three decades. This chapter traces structural reforms in the power sector across major economies of the world, compares against Indian experience and reflects on the impact of such reforms on the commercial viability of renewable.

Breaking Monopoly During the first wave of liberalization in the 1990s, governments across the world began to reassess the structure of the electricity industry. An understanding that electricity is as tradable a commodity as any other was one of the influences behind these developments. It was argued that once a monopoly over wires and dispatch was suitably set apart and controlled, electricity could be competitively supplied at wholesale and retail levels. Based on this logic, many countries went ahead with

the task of developing competitive markets in the generation and retail segments in their own power sectors. Some governments also viewed privatization and competitive markets as a God-sent opportunity for reducing involvement in their own power sector. Deeply steeped in debts as they were, many were no longer in a position to finance the future expansion of their power sectors. They, therefore, used this as a means to transfer at least part of their responsibilities to private participants. In one of the earliest attempts at introducing competition in the power sector, competitive bidding route was adopted for investments in generation. The main purpose behind this was to get private parties to invest in generation while leaving the complex matter of network operations and long-term planning with the central organization. From the point of view of RE technologies, one of the major difficulties with this process was getting the organizers to accept new technologies in the tendering norms.1 Moreover, it was costly and cumbersome for small-scale players to get themselves involved in this process. Yet it would be foolish to believe that changes in the sector were being initiated solely with small-scale renewable technologies in mind. These markets, in fact, had overgrown the scale and were ready to absorb enterprises in large numbers, irrespective of the technologies or plant sizes they chose to bring into the market. The next attempt was to give open access to generators for wheeling of power on transmission lines, against payments for transmission charges and the fulfilment of certain technical requirements for the grid connection. The high cost of setting up wheeling contracts, especially in the case of smaller players, and the option available to transmission companies for refusing contracts on technical grounds, significantly hampered the development of competitive markets in the process of generation.

Power Trading and Pooling England and Wales instituted a pooling system for power trading. In this model, complete freedom was given to bulk

16  Renewable Energy in India

consumers and distributors to buy electricity directly from power generators, traders or from the electricity pool. An open access to wires was created to back up the trading process and a central dispatch system—to be operated by the independent system operator (ISO)—was instituted. After privatization in 1990, England and Wales divided their power industry into four separate activities, namely generation, transmission, distribution and retail. Central planning was disbanded, and the power supply was shifted to a competitive platform for trading in the power pool. All final consumers were allowed to choose their own supply, not only from the existing suppliers but also from any that chose to enter the field subsequently. The new regulator, using price caps or an incentive formula, set prices for monopoly segments, namely transmission and distribution. In contrast, markets set prices in competitive segments, namely generation and supply. However, they remained under close vigil of the regulator. The results of the British reforms were mixed; after a decade, it was still in transition and, according to some accounts, evolving rapidly, but in an unpredictable manner.2 With privatization, electricity generation in England and Wales was set to run in a manner as if fully competitive. The electricity market was meant to set its own prices for generation without any aid from the regulator. In reality, what ensued was a mix of bilateral contracts and the power pool.3 Under power pools, generators who wished to operate their power plants had to bid successfully for specific time slots. The bids had to be placed 24 hours in advance of each of the 30-minute block of a 24-hour day. Although plants were scheduled according to the merit order on the basis of their bid prices, in practice, they all were paid the same rate that corresponded to the highest bid price from among the successful contestants. All of the wholesale suppliers, on the other hand, had to buy from the power pool at a market-clearing price. However, bilateral contracts between generators and suppliers were allowed to subsist and even bypass pool rates. These

Structural Reforms in Power Sector  17

were essentially known as contracts for differences. In the first instance, while all transactions were put through at the pool price, generators and buyers settled any difference that arose between the pool and the contract price between themselves. When the pool price was higher, the generators reimbursed the buyers for the difference and vice versa. The underlying logic behind allowing these contracts was to provide a hedging mechanism against long-term price risk that arose from the volatility in spot market prices nearer the actual dispatch and due to cyclical and seasonal changes in demand and supply. It was necessary for this reason to provide an arrangement that would allow generators and customers seeking certainty to enter into contracts and secure them against risk. Typically, in such a system, generators looking for certainty could seek long-term contracts in sufficient numbers to cover a significant portion of the proposed capacity before actually investing. They could thus reduce their long-term risk. It was anticipated that the pool would act as a fulcrum, balancing and facilitating operations with a significant proportion of transactions passing through it. The contract market, on the other hand, drawing on the experiences from the pool prices, would evolve its own set of prices. Unfortunately, in practice, things did not quite work out the way it was anticipated. In fact, little power was bought and sold at pool prices, as they were widely mistrusted. Eventually, the system had to be abandoned and the New Electricity Trading Arrangement (NETA)4 had to be brought in its place. Despite its initial failure in Britain, the pooling concept for trading in electricity won a significant number of subscribers across the world. It was deployed in various countries of the world—Australia, Norway, Argentina, New Zealand and Israel, to cite a few—with suitable modifications to its basic design, reflecting lessons learnt from its initial operation in England and Wales, and their own situation. The factors behind the pool’s failure were complex. One of the main reasons was its premature launch, even before software for trading was ready. Its failure in creating the desired 18  Renewable Energy in India

amount of liquidity in the market, as originally envisaged, was another reason why it was abandoned in its initial form; in fact, the presence of a long-term contract system undermined its evolution. Dominated as it was by the operations of its two most powerful generators, the pool displayed all signs of price manipulation. Despite these setbacks, the pooling system has continued to be viewed as the most preferred option for opening up of the power sectors to competition. The fact that electricity reforms have been tailored on similar lines worldwide is proof of this. Broadly, there have been two pool designs. The first of these was the original English model based upon the principle of mandatory market. It required all electricity to be traded through the power exchange (PX). Comparatively, the Nord Pool market of Scandinavia requires that only surplus power, over and above bilateral contracts, be traded through the pool. The bids in this system, unlike the mandatory pools, are tied to the operating company and not to the plants. Interestingly, NETA, which replaced the mandatory pooling system in the UK, has been the same as Nord Pool, which developed from innovations in the former English and Welsh pooling models.5 NETA, besides the half-hour settlement system and other aspects that remain the same as in the original model, also includes forward and future markets. These markets allow contracts for electricity to be struck up for several hours in the future along with short-term PX that allow participants to finetune their contracts in a simple manner. The demand side of the electricity market, unlike the previous pooling system, is fully represented in the new model.

Competitive Markets The preoccupation with creating competitive markets stems from the well-established principle of economics, which postulates that, in normal circumstances, markets are the most effective means for efficiently allocating resources between

Structural Reforms in Power Sector  19

various consumer segments, provided they are competitive. Supply, in such markets, is driven by the incremental cost of producing additional units—also known as short-run marginal costs (SRMCs). The market clears at a price where the marginal cost of supplying electricity is equated with consumers’ willingness to pay for it. The monopoly or any form of collusion is seen as antithesis to markets and requires close regulatory involvement. For the sake of economic efficiency, in such situations, tariff regulation requires the pricing of electricity on the basis of SRMC—just as in other markets—with a view to balancing electricity demand with supply in the short run; and, in the long run, on the basis of long-run marginal cost (LRMC). The latter is meant to efficiently channel investments in the future expansion of the sector. Thus, there is a stamp of economic efficiency associated with the use of these two costs as the basis for setting tariff. Most of the concerns with respect to tariff regulations in such cases centre on the feasibility of using these methodologies as the basis for electricity tariff formation. In this background, the central purpose behind the unbundling of the sector and trading-based pool is to create a competitive industry structure by demerging it into various activities. The industry is divided into its competitive constituents and those requiring closer regulatory scrutiny. The ultimate benefit of unbundling is that it is meant to help remove any possibility of price manipulation by dominant players who could use their clout from one segment to gain advantage in the other. For example, it could curb the possibilities of cross-subsidization between generation and retail services which operate under competitive conditions, on the one hand, and transmission and distribution services, which even in pool function as monopolies, on the other.6 To prevent any such possibility, electricity pools need be run by centralized independent organizations— defining the bidding process and organizing dispatches at market-clearing prices.

20  Renewable Energy in India

The overall design in this system has to be able to offer sufficient stability and predictability, and ensure that investments in new generation capacity are not intolerably risky. In fact, the contract market in England and Wales was meant to perform this very function. But, for reasons explained, it instead dried up liquidity and affected the operations of the regional pool markets and, in the process, defeated its original purpose. One of the main lessons learnt from this experience was that in countries having a history of monopoly in electricity generation, the newly unbundled generating utilities could still have a large market share and, therefore, exercise their clout. If this were not checked, it would defeat the original purpose behind setting up of electricity pools. For these reasons, the unbundling process has followed different routes in different countries. Some have gone in for organizational unbundling, where, without changing the original ownership, there has been an organizational and accounting separation of activities, namely generation, transmission, distribution and supply.7 Although this may be a far cry from the original purpose of unbundling, it has the merit of introducing transparency in the overall operation of the power system; at least in the short run. There are others who, by virtue of already having a sufficiently competitive generating segment, have felt comfortable in straightaway launching short-term pool exchange. However, they have continued to regulate transmission and distribution activities in their electricity industry.

Unbundling in India The tariff-setting mechanisms have varied across countries, depending on which of the several approaches they have adopted in pursuing electricity reforms. But the main issue in the context of unbundling with RE technologies has been: can these technologies cope with the structural reforms that are taking place in the power sector around the world and, if so, how? At the time when the Indian power sector is being reformed, the issue pertaining to competition and market Structural Reforms in Power Sector  21

efficiency is as important to its RE initiatives as it has been to initiatives of a similar nature in other countries of the world. This is so, especially since the thrust of the EA, 2003, in India has been clearly to unbundle and open access, leading ultimately to the introduction of competition in its power sector, as and when feasible. In fact, Orissa and Delhi Electricity Boards embarked on this route even before the EA, 2003, came into effect. Several others have followed since then. Barring power dispatch and transmission, the EA, 2003, opened all other power sector operations to private entry.8 For that matter, even while control over transmission has remained with government agencies, there is provision for private entry in certain aspects, as reflected by the creation of the ‘transmission licensee category’ in the Act. Whichever way one looks at it, unbundling, with its focus on creating competition, has been an important development in the Indian power sector. As far as RE technologies are concerned, though privatization has not been an issue—as most of these units are privately owned—competition, as it is usually defined, has remained so. As any economist knows, despite the tag of efficiency, markets are woefully inadequate in dealing with a host of situations lumped together under a common label ‘market failures’; and, as it will be clear later, the pooling system has been no exception. The key competitive charge in the short-term pool market is the generation price. Power pools provide the model for achieving the most efficient dispatch, given the SRMCs of supply. In this system, the least cost of dispatch of the pool and that of a competitive market is one and the same, so long as the transmission is unconstrained. However, this complicates short-term market operations, not only by aggravating power losses in the system but also by blocking the passage of electricity in wires. In a typical transmission network, it is rarely the case that power flows from point to point. Transmission congestion constrains the long-distance movement of power in some segments

22  Renewable Energy in India

of the grid while imposing higher supply costs in others. This aspect would have been particularly relevant to the Indian situation if the power sector had adopted the pool system. Anyone who is even remotely familiar with the Indian power industry knows well how investments in intrastate transmission and distribution have grossly fallen short of requirements over the years.9 In normal circumstances, power would flow from low-cost to high-cost regions. In contrast, in the background of transmission constraints and periods of high demand, cheaper plants in low-cost areas are sidelined as costlier generating units located in unconstrained regions supply power there. In such a scenario, though the economic dispatch would still be the least cost, the bids would have to be location specific and recognized as the minimum acceptable price at the concerned location. Thus, in the presence of transmission congestion, the generation contract, though necessary, is insufficient to provide the required long-term hedge. Bilateral generation contracts can capture the effect of aggregate movements in the market—when a single market price is up or down—which is not the case once transmission constraints come into the system. Transmission congestion gives rise to multiple location-specific prices, due to which the generator alone cannot provide back-to-back hedge on fluctuations of short-term electricity prices. The solution in this case is to redistribute congestion revenue—due to differential prices—through the system of long-run transmission congestion contracts. This, in turn, runs parallel with the long-run generation contracts, the settlement again being through the contract of differences, just as in the case of generation.10 From the RE technology angle, the transmission constraints can be double-edged. On the positive side, it can be potentially favourable, at least in the short run, for those RE units which are situated on the unconstrained side of the transmission. Further, in a truly competitive market, the transmission constraint could provide an opportunity to RE technologies to be

Structural Reforms in Power Sector  23

seriously included in the investment options being examined for easing the power supply situation in the areas affected by the constraint. However, in reality, there have been some serious misgivings among the advocates of RE technologies over the pool system. For one, it has been argued that since RE units are usually small in scale, it is not always economically worthwhile for them to enter into such contracts. If the cost of seeking customers or taking up distribution on one’s own is prohibitive, it is often the same with costs of PX membership. Further, the costs associated with making RE technologies compatible with the grid are high—since protocols for grid interface have evolved over the years in response, predominantly to the needs of conventional technologies. One of the major issues concerning RE units in India is that they are site specific and often located in rural areas where hightension grid may not be available. The nearest substation may be at a distance at which the cost of erecting tie-up lines can be prohibitively high in the case of isolated units. One approach to resolving this problem could be to hook these units up with the distribution system. Unfortunately, distribution networks are designed for different purposes than transmission networks. They usually have unidirectional power flow with little or no inbuilt redundancy. Generally, from the grid angle, control over generation from these sources becomes difficult for the system operator, as low-voltage ends of the distribution lines are usually not connected with the central system.11 There is an added complexity in the Indian context. In areas where there is no high-tension grid, these units are connected to the local grid at 11 kilo volt (KV) level. Since, in times of load shedding, it is these substations that are cut off from the main grid, their effect is to block off the export of power from these units. Also, some renewable units, such as co-generation, perform best only when connected to the grid at 66 KV level. But, in India, this level of transmission is on the wane and is being replaced by 110 KV.

24  Renewable Energy in India

Another issue that invariably figures in any debate on the commercial viability of RE technologies is environmental costs. In comparison to conventional power plants, these are clean technologies with no external costs. Proponents of RE technologies argue that the costs of polluting power stations, if included in their unit electricity costs, will nullify any cost advantage that they may have over renewable power units. The market’s inability to institutionalize this aspect of power generation is a classic market failure often referred to in textbooks. Billions have been spent on finding a politically acceptable answer, and though carbon trading and clean development mechanisms (CDMs) have since evolved, these are still to be put into practice globally.12 The main problem with RE technology has been that though some of them are technically and economically viable, commercially they are still lagging behind. If one ignores externalities, then the financial estimates of per unit life cycle cost of electricity generation from these technologies and conventional power plants have been comparable. But when it comes to estimating these costs in commercial operations, things have been completely different. For instance, given the intermittent nature of wind and solar resources, RE projects based on these resources cannot be treated as firm. There are, therefore, system balancing costs associated with the integration of wind and solar projects. This concern gets aggravated when the penetration level of variable renewable increases in the power system. Naturally, therefore, this is currently a major area of debate, as the share of renewable has increased substantially and is likely to increase exponentially in the foreseeable future. There are reports13 that point to additional RE integration cost exceeding `1/unit resulting from additional gas-based generation cost, additional deviation charges, standby charges, extra transmission charge, etc., to accommodate variable renewable as must-run plants. One of the major issues has been that several RE units have had high capital costs but low short-run costs. Besides, the financing structure of these projects has complicated the matter

Structural Reforms in Power Sector  25

further, as principal and interest payments have been high during the years when debts were being repaid (generally 10 years). In a dynamic situation when technology is still evolving commercially, this becomes a significant barrier, even more so when promotional policies change without providing protection to earlier investments.

Chapter Conclusion The structural reforms, especially the breaking of the monopoly and the ushering in competition, leave a significant commercial impact on renewable. Renewable, when weighed against only its investment cost and variability, appears to be non-competitive. The financial cost comparison between renewable and conventional plants makes renewable look expensive (though trend is changing in recent times). However, if one considers the low short-run cost of renewable and also the factors in the external costs (environmental costs), renewable turns out to be more cost-effective. The need is to recognize these realities and not only to protect in the restructured system the investments made in the past but also to create conducive environment for renewable to sustain with its long-term positive effects. It is in this context that the next chapter details the various promotional policies experimented in different parts of the world and compares them with those in India with a focus on the impact of such policies on the market creation for renewable.

Notes 1. Thomas Ackermann, ‘Distributed Resources in a Re-regulated Market’ (Doctoral Thesis, KTH Electrical Engineering, Stockholm, Sweden, 2004), 74. 2. Steve D. Thomas, ‘Tariff Setting in Privatised British Electricity Industry’, in The Indian case Study in Regulation in Infrastructure Services: Progress and the Way Forward, ed., S. K. Sarkar and Kaushik Deb (New Delhi: TERI, 2001), 105–118. 3. Review of Electricity Trading Arrangements Background Paper 1 Electricity Trading Arrangements in England and Wales (February 1998). https://www.ofgem.gov.uk/ofgem-publications/79088/

26  Renewable Energy in India

review-electricity-trading-arrangements-background-england-andwalespdf 4. www.Inencogroup.com/neta.html (accessed on 8 February 2021). 5. Ibid. 6. Thomas Ackermann, ‘Distributed Power Generation in a De-regulated Market Environment, Part I’ (First Draft Working Paper, Royal Institute of Technology, Stockholm, Sweden, 1999), 25. 7. K. Ramanathan, ‘Choice of a Power Market Model in India in Transition to Liberalized Environment: Experiences and Issue in Regulation’, ed., Leena Srivastava and S. K. Sarkar (New Delhi: TERI), 128–136. 8. The EA, 2003. 9. M.S. Bhalla, ‘Transmission and Distribution Losses in India’, in The Indian Case Study in Regulation in Infrastructure Services: Progress and the Way Forward, ed., S. K. Sarkar and Kaushik Deb (New Delhi: TERI, 2001), 165–174. 10. William W. Hogan, Transmission Investment and Competitive Electricity Markets (Cambridge, MA: Center for Business and Government, Harvard University, 1998), 10. 11. Ackermann, ‘Distributed Power Generation in a De-regulated Market Environment’, 37. 12. European Wind Energy Association and Greenpeace, ‘Wind Force 12, A Blueprint to Achieve 12% of the World’s Electricity from Wind Power by 2020’ (2004), 16. Available at http://www.greenpeace.org/usa/wp-content/uploads/legacy/Global/usa/planet3/ PDFs/windforce-12-2004.pdf (accessed on 8 February 2021). 13. https://www.cea.nic.in/reports/others/planning/resd/resd_comm_ reports/report.pdf, 13–18 (accessed on 8 February 2021).

Structural Reforms in Power Sector  27

3

Policies Supporting Renewable Aid to Market Formation

Introduction Nations across the world have come up with policies promoting renewable. These policies have reiterated the need for special treatment for renewable, and the support has ranged from fiscal incentive, capital subsidies, feed-in tariff (FIT) guaranteeing grid access and fixed tariff, to concessional transmission pricing and so on. India is no exception. This chapter captures the global policies supporting renewable, dwells at length on Indian initiatives and presents a perspective on how these policies have helped market creation for renewable.

Global Approaches to Supporting Renewable Energy Technologies A usual approach that most of the governments promoting RE programmes around the world have taken in dealing with

these issues is to forcibly create markets for these technologies by introducing specific laws and regulations favouring their promotion.1 These technologies have been backed up with preferential tariffs, subsidies and various other fiscal incentives in the last 30 years. In Europe, feed-FITs have been used very effectively to get RE technologies off the ground. Several governments in Europe have made it obligatory for power utilities to connect local renewable power-generating units to the grid and pay them the FITs. These tariffs have been fixed at different levels for different technologies. By securing income and reducing the risk for developers, various governments have successfully boosted their commercial deployment. For example, Germany’s relatively high FITs have led to its emergence as the world’s largest wind turbine market.2 With a view to spurring investments in RE development immediately after the 1947 oil crisis—the US government provided investment tax credits, and research and development funds to those engaged in RE technology. However, the enactment of the Public Utility Regulatory Policies Act (PURPA) in 1978 was the single most important factor in the development of a commercial RE market in the country.3 PURPA created a qualifying facility status for these units and co-generation technologies, mandating utilities to purchase power from them at their full-avoided cost. It also encouraged utilities to enter into long-term contracts of 10–15 years with them. As a result, the rates paid to RE units in the USA were unusually high in 1980.4 In contrast, in Britain’s Non-Fossil Fuel Obligation (NFFO), potential renewable project developers—after bidding successfully under each RE technology category—were awarded tariffs, as stated in their bids, for a predetermined period (15 years). Unlike the fixed FIT approach of other countries, this approach proved advantageous, spurring cost and tariff reductions. For example, the price of wind electricity dropped in the UK from 8–9 pence to 4 pence in six years in the 1990s.5 It was, however, not clear whether this drop was due to developers confining their new investments only to clearly advantageous wind sites or to the deployment of more advanced technology, or both. Policies Supporting Renewable  29

In the last couple of decades, the electricity industry has increasingly come under regulatory and economic pressure to become more competitive. In fact, in the mid-1990s, the Federal Energy Regulatory Commission (FERC) ruled against some states in the USA for using rate-setting mechanisms to set RE rates above the avoided costs. Competitive pressure in the power sector has since increased in that country and elsewhere, seriously affecting the future of RE technologies in several ways.6 One suspects that as utilities are forced to compete more heavily on price in the short term, the flexibility to experiment with RE technologies could be diminished. In such situations, the premium for short-run cost minimization would increase substantially, squeezing out technologies that are not costeffective over a short period of time. Utilities that might otherwise have invested in technologies that are cost-effective in the long run but carry high short-run costs would be less likely to do so once there is a competitive pressure. Nor would they want to roll out expensive generation together with the less costly ones if the plant-based merit order dispatch is in practice. In such a scenario, they would be more inclined to consider each power source independently and determine whether it is competitive. Similarly, they would have little incentive to spend money on the development of technologies that offer common benefits to all generators. Further, increased competition would potentially have the effect of diminishing the importance of beneficial attributes—non-polluting and risk-reducing aspects— of RE technologies. For this reason, in countries that promote RE technologies, distributed generation is often relatively unencumbered by the rules of central systems (scheduling, pooling, dispatch). In the UK, embedded power stations, including renewable units, with a total registered capacity of up to 50 MW, do not have to trade through the pool and are not dispatched through the system operator (grid). 30  Renewable Energy in India

However, they have to comply with the distribution code, though not the grid code. As far as excess supply is concerned, it has to be sold to authorized suppliers or end users. In NFFO’s case, public electricity suppliers were obliged to buy all power output from renewable units and, in turn, reimburse the price difference between the market price and the NFFO tariffs. In fact, Sweden, Germany and Denmark have special regulations for RE generation. Under the Swedish system, concession holders are forced to buy all power from small-scale generation at tariff rates representing their avoided costs.7

Indian Approach to Supporting Renewable Energy Technologies In India, until 1993–1994, the MNES had adopted a subsidy route for promoting non-conventional energy technologies in the country. But, in that year, it switched to a commercial approach, promoting these technologies through private investments. The MNES (presently MNRE) had initially examined two models, one based on competitive bidding and the other on fixed tariffs. Eventually, it settled for the latter on the grounds that this was the most widely prevalent approach worldwide. It was also easy to implement.8 Before formalizing its approach, MNES (presently MNRE) met with several states and discussed the policies they were pursuing with respect to IPPs for encouraging investments in conventional power plants based on fossil fuels. It found that the tariffs for these projects ranged between `2.50 and `3.00. Taking these figures as a benchmark, the Ministry prescribed tariffs for the purchase of power from various renewable source of energy. It maintained `2.25 per unit as the base for rates to be charged in the future, stating that this being the avoided cost of thermal power, was appropriate as the base for granting future tariff escalations. And it thus added escalation clauses to provide for any inflationary increase in the future. Keeping this as the basis, several states evolved their own policies for the promotion of RE supply to the grid. These Policies Supporting Renewable  31

policies were challenged by various SEBs under the ERC Act, 1998. Most SERCs, except the MERC and the Andhra Pradesh Electricity Regulatory Commission (APERC), restored the base line tariffs as specified by the MNES through their rulings. The MERC and the APERC, on the other hand, took it upon themselves to evolve their own guidelines based on the Central Electricity Authority’s (CEA) methodology.

Promotion of Renewable under Electricity Act, 2003 With the introduction of the EA, 2003, the practical expediency on which the MNRE approach was based could not be the sole guiding principle for tariff setting. It required any tariff principle to address some basic issues concerning the impact of the tariff on the overall efficiency of the sector as well as on the economy.9 However, this was easier said than done. With the notification of the EA, 2003, as mentioned earlier, the Indian power supply network began undergoing a major overhaul. As things stood now, the Act was designed to unbundle the power network and create competition on the supply side by widening consumer choice with respect to electricity suppliers, both at retail and bulk levels. In view of the complexities involved in changing over to the new structure, the EA, 2003, stipulated its phased implementation in the future (Section 42 [2]). In short, the Act created a level playing field with an independent regulatory authority to attract and sustain private investment in a competitive environment. Under the previous legal framework, all private generation (including renewable), whether for captive consumption, third-party sale or for supply to the state grid, required prior sanction from the SEB/state government. In contrast, under the EA, 2003, generation (Section 7) was de-licensed. As regards third-party sale, open access on intervening transmission lines was provided (Section 35) to the extent of the surplus capacity available. Thus, anyone can now set up a power plant based on

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RE sources and supply electricity either to a distribution licensee or to a captive industrial unit. While there was a provision earlier in the now superseded Electricity (Supply) Act, 1948 (Schedule 6), specifying that the electricity price be based on the cost plus the minimum return on equity, this provision was omitted in the new Act. The states’ regulators now have to be guided by the principles and methodologies specified by the Central Commission for the determination of tariffs applicable to generation and transmission companies (Section 61 [a]). They have to give due consideration to the competitive environment, the potential for efficiency improvements and, from time to time, the overall guidance that comes from the National Plan and Tariff Policy (Section 3). Further, all factors that encourage and promote competition, efficiency and better use of resources, good performance and optimal investments (Section 61 [c]) need consideration in such exercise. Had the new Act stopped here, it would have meant a doom for the RE technologies, many of which have been still evolving. Their commercial costs have been generally high and, on the basis of merit order dispatch, probably none would qualify. A few that are on the verge of commercial viability need support to accelerate their progress towards this goal. Fortunately, the Act stated that the tariff regulation will incorporate ‘…the promotion of co-generation, and generation from renewable sources of energy’ (Section 61 [h]). It has thus been clear that the tariff regulation of the commissions has had to be guided by the promotion of co-generation and RE technologies in the last few years. While the Act had more focused reference to the promotion of RE, it did not specify any prior quantitative targets. It left this to the SERCs. They have thus promoted electricity generation through renewable sources, by providing suitable measures for their connectivity with the grid and by specifying—if they consider appropriate—a certain percentage of the total supply of electricity to a distribution licensee’s area to come from these

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sources (Section 86 [1] [e]). The Act has also had an enabling provision—through government policy—for the establishment of stand-alone systems based on RE for rural areas (Section 4). Although the EA has focused on the improvement of efficiency in supply, it has not directly addressed the demand side in the energy supply and demand equation, except promoting co-generation. This lacuna has, in fact, been taken care of by the Energy Conservation Act, 2001. On the whole, it is safe to say that the Act has had all the necessary ingredients for facilitating the propagation of RE in the country.

Tariff Setting Even as the Act listed the guiding factors for the tariff-setting exercise to be taken up by the ERCs, there has been an extensive debate over the suitability of applying various cost concepts in arriving at bulk tariffs for the grid supply. Typically, the debates have reflected the difference of opinion between practitioners and economists. Complicating the issue further—which is particularly relevant to RE pricing—has been the notion of fairness. On the one hand, these sources are not given due credit for their nonpolluting aspects. On the other hand, as the commercial cost of producing electricity from these sources has been, on average, higher than that for conventionally produced electricity, a question that has often come up is what impact these would have on retail tariffs if the costs are allowed to pass through to that level. And, if not, what would their impact be on the state governments’ finances, as the subsidy would ultimately have to be borne by them. But the complication does not end here. As mentioned earlier, these technologies have been still commercially evolving. With economies of scale, their supply costs have been falling; though not sufficiently to make them competitive commercially with conventional technologies. Until they achieve competitiveness with respect to these technologies, someone

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has to pick up the bill. The question is: who should this be? Clearly, RE technologies have had to be given a tariff support and a regulatory oversight within the framework of the Act over various aspects of costing, irrespective of whichever concept of cost is put to use. Further, one still has had to decide on the appropriate principle for fixing RE tariffs. The two most commercially applied cost concepts have been the variants of the ‘rate of return’ method. One of them involves costing of every aspect of the operation and topping it up with a predetermined rate of return on equity; the second, known as performance-based pricing,10 requires the application of an annual escalation rate, which, though linked to the retail price index (RPI), is, unlike the former, adjusted by an efficiency factor negotiated between the regulator and the generator. These two tariff methodologies have been broadly labelled as the cost-plus approach. The two most widely discussed cost concepts based on the application of economic principle have been avoided costs and marginal costing. The latter has two variants, the SRMC and the LRMC, as discussed earlier. The avoided cost approach as applied to RE pricing was first mandated in the USA under the PURPA, in the late 1970s, when utilities in that country were required to purchase power from the qualifying facilities at their avoided costs. However, by the mid-1980s and the early 1990s, oil prices stabilized, natural gas prices declined and the excess capacity in most regions of the USA allowed utilities to buy capacity and energy at much lower prices. Subsequently, the utilities’ actual avoided costs dropped to much lower levels than what they were when the first contracts were signed. After the FERC refused to allow the states to set rates above the avoided costs prevailing at that time (early 1990s),11 this methodology was virtually abandoned for the purpose of pricing electricity from renewable sources. More recently, the support to RE technologies in that country was provided through the renewable portfolio standard (RPS) approach.12

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Returning to the Indian context, there has been an added issue to using these costs as the basis for pricing electricity from renewable sources. It relates to identifying a generation source that is being displaced as a result of the induction of RE supply to the grid. This requires an elaborate network analysis of the varying system conditions before zeroing in on the source that is being displaced by a particular RE unit. Although this may be fine as an academic exercise, its practical application is limited. It would require the installation of a sophisticated information network for monitoring the generation source being replaced. This brings us to marginal costing. A question that may be asked is how relevant is its application for fixing electricity tariffs in India, especially when this is produced from RE sources? As said earlier, the issue here stems from the fact that most RE units have proportionately very low variables but high capital costs. It means that entrepreneurs cannot recover their initial investments if they are paid a tariff that is equal to their SRMCs. In fact, even with avoided costs that are much higher than the SRMC, these units would find it difficult to recover their investments. Tariffs based on both the avoided costs and the SRMC would discourage private investments in these technologies at the present stage. For that reason, it is often argued that these units must be paid tariffs based on their LRMC, which would take care of both, the investments and the variable costs, and leave the developers with a reasonable rate of return. Were RE technologies mature, this would indeed be true. But, as things stand, these technologies are still commercially evolving. Capital costs, measured in terms of per unit of capacity, are falling with the advances in generating technologies of these units. It means that even tariffs based on LRMC would not be able to recover all costs and some additional fixed charges would be necessary to guarantee that developers recover their future investments. Besides, the estimation of LRMC is meaningless if it is carried out independently of long-term planning exercises

36  Renewable Energy in India

for future capacity additions and power procurement plans of power utilities. Since most RE technology developers are small-scale IPPs, it is difficult to visualize them undertaking such an exercise. For that reason, the full cost methodology has a practical value for regulators as it enables them to periodically review all elements of unit costs of electricity produced from renewable sources, factor in the most recent advances in these technologies and to separately fix tariffs for generating units of each technological vintage. As long as this energy source does not form a significant proportion of the total electricity generation in the country, its impact on retail rates, if any, would only be minimal. In fact, it is more important that these concepts are first implemented in conventional power plants, which form the major portion of the power supply in the country. Until recently, the transmission pricing was not the concern of electricity-generating units based on RE sources worldwide. Having sold power to vertically integrated utilities, they did not have to separately negotiate transmission and distribution rates with them. In contrast, in India, SEBs have had their own policies with regard to the charges on transmission access given to these units for supply to third parties or to the principal manufacturing units which set up these as captive units.

Transmission Pricing With the stipulation of unbundling and non-discriminatory open access in the Act, the relationship between utilities and renewable units described above changed, at least on paper. These units have, in the new structure, been dealing with not the former vertically integrated utilities but with unbundled identities such as transmission utilities or licensees, or distribution entities. In this background, transmission facilities would have to be built upon the expectation that such investment would eventually be recovered through appropriate rate-making procedures. In this respect, CERC has provided guidance, which

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hopefully would act as an incentive for investments in transmission capacity when needed and, at the same time, utilize facilities that are already on the ground in the most efficient manner. As RE-based power units are often located remotely from electricity demand centres, it matters significantly how transmission access is charged to them.13 A fact that power flows not from point to point, but in loops and parallel paths, is a major hurdle in pricing transmission. Congestion in wires further adds to this complication. As far as renewable resources-based power systems are concerned, these aspects can affect their viability in an unpredictable manner. For this reason, pricing schemes based on the ‘contract path’ method, which are not scientific (as power flows based on the laws of physics and not on path between contracting parties) and are generally considered to be inappropriate, whereas alternative flow-based pricing methods, such as megawatt-mile rates, are complex and difficult to calculate. Although the latter is based on parallel power modelling techniques, it gives no credit for counterflows and is administratively far more complicated than other methods for tariff calculations. In this method, the rate for each transaction has to be calculated for each change in the transaction as well as for each additional transaction. On the other hand, the problem with methods such as marginal cost pricing is that these costs of transmission are only a fraction of the fixed capital charge. Hence, in practice, pricing schemes for transmission have tended to set these rates well above these costs, with an ultimate aim of recovering fixed charges. Unfortunately, that is where all the problems lie. The methodology used to recover these fixed charges can dramatically change the allocation of these costs among different types of generation. For example, rates that have high firm charges as components of transmission tariffs can affect the competitiveness of renewable resource-based power units, depending on the degree of their infirmity. In general, transmission charges have to be related to one or more of the following, namely the

38  Renewable Energy in India

quantum of electricity that is being transmitted; the distance to which it is being transmitted and the transmission capacity reservation. How transmission pricing schemes affect the viability of renewable technology power units ultimately depends on how the various characteristics of these technologies are related to the above factors. Yet, given the thrust of the the government’s policies towards renewable power supply to the grid, this is something that every regulatory commission will have to focus on. The latest transmission pricing framework14 (CERC [Sharing of Inter-State Transmission Charges and Losses] Regulations, 2020) is relevant in this context. It does factor in the features of the transmission capacity reservation or access, usage and distance/direction. However, a major share, about 80 percentage of the transmission charge, is likely to be based on transmission access and balance on usage. The logic is that investment in transmission has to be recovered as a fixed charge in MW terms linked to the transmission capacity reserved or access granted on a long-term basis. Any framework based purely on usage would lead to under-recovery of investment. However, for renewable generators, the transmission pricing framework based on transmission access/use becomes burdensome. Their capacity utilization is quite low—on average in the range of 20–30 per cent and, as such, they would end up paying for 100 per cent of the capacity despite using the transmission system only marginally. The question is: whether there is any way out of this dilemma? The international experience offers possible options to address this predicament. In several countries, the principle as adopted by CERC is followed but with one exception that transmission charges and losses are entirely borne by the buyers (and not the sellers or generators) on the ground that, at the end of the day, transmission charges and losses in any case get passed on implicitly or explicitly to the buyers. For instance, in California, transmission revenues are collected through the California ISO’s transmission access charge (TAC), which is charged to demand (to internal load and to exports).15 Supply resources do not pay the TAC, so that resources can base their

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bids for scheduling and dispatch on marginal costs without adders such as the TAC. CERC has taken a step forward, though half-hearted, in this direction. The right course of action is to adopt the model—of the buyer bearing fully the transmission charges and losses—at the earliest. This will not only encourage investment in the renewable segment but will also bring the desired simplicity and clarity on transmission pricing.

Chapter Conclusion RE technologies are inherently different from conventional resources on account of their variability, substantially lower capacity utilization factor and high capital cost but low shortrun cost. It’s obvious, therefore, that nations across the globe have carved out special dispensations for renewable with due regard to their importance for environmental protection. These dispensations, especially on pricing and special network access rights, have laid the foundation for their mainstreaming with the market operation in general. While the focus of this chapter was on large-scale grid-connected renewable projects, a separate discussion is considered necessary on small-scale distributed energy resources, given the differences in their dynamics. Accordingly, the next chapter discusses policies supporting various business models and pricing strategy for distributed energy systems.

Notes 1. Ackermann, ‘Distributed Power Generation in a De-regulated Market Environment’, 55. 2. European Wind Energy Association and Greenpeace, ‘Wind Force 12’, 14. 3. Michael J. Zucchet, ‘Renewable Resource Electricity in the Changing Regulatory Environment’, Renewable Energy Annual (1995): 25. Available at https://inis.iaea.org/collection/NCLCollectionStore/_ Public/27/045/27045864.pdf (accessed on 8 February 2021). 4. Ibid., 26.

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5. Ajay Mathur, ‘Regulating Technological Change in the Electricity Sector: Thinking Beyond Today’, ed., Leena Srivastava and S. K. Sarkar (New Delhi: TERI, 233–237), 1999. 6. Ackermann, ‘Distributed Power Generation in a De-regulated Market Environment’, 55. 7. Ibid. 8. MERC Order (16 August 2002) for Non-Fossil Fuel-based Co-generation Projects, Sec. 3.2 ‘Approach’. 9. Pramod Deo, ‘Electricity Act 2003—Its Implications on Promotion of Renewable Energy and Efficiency’ (Paper Presented at International Congress on Renewable Energy, ICORE, January 2004). 10. Ahluwalia and Bhatiani, ‘Tariff Setting in the Electric Power Sector’, 67–104. 11. Zucchet, ‘Renewable Resource Electricity in the Changing Regulatory Environment’, 27. 12. European Wind Energy Association and Greenpeace, ‘Wind Force 12’, 16. 13. Larry Prete, ‘Transmission Pricing Issues for Electricity Generation from Renewable Sources’, Energy Information Administration/ Renewable Energy 1998: Issues and Trends (1998), 47. Available at https://corpora.tika.apache.org/base/docs/govdocs1/601/601899. pdf (accessed on 8 February 2021). 14. http://cercind.gov.in/2020/regulation/158-Reg.pdf (accessed on 8 February 2021). 15. http://www.caiso.com/Documents/DraftRegionalFramework Proposal-TransmissionAccessChargeOptions.pdf (accessed on 8 February 2021).

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4

Distributed Energy Resources Business Models and Market Dynamics

Introduction Small-scale distributed renewable energy (DRE) systems are placed differently compared to large-scale renewable projects. The former involves a direct interface with end consumers and in remote rural areas where the grid may or may not have reached. Such ventures, intertwined as they are with socioeconomic milieu of the population and being dependent on locally available renewable resources, need different treatment in terms of policy and regulatory support. This chapter traces initiatives in this regard in India, compares them against policies in other parts of the world, with focus on business models and pricing of electricity from such distributed energy resourcebased projects.

Distributed energy resources are generally referred to as resources that can provide services locally at the consumer end, at the distribution level and could be off-grid or gridconnected. In the international literature, resources such as demand response, storage systems, electric vehicles and solar photovoltaic (PV) cells are included in the discussion on distributed energy resources. There are a number of business models around this concept and across different parts of the world, for example, market-based and utility-supported demand response, behind-the-meter energy storage, network service-based energy storage, solar plus storage model, to name a few.1 However, given the central theme of the book, we largely cover policy interventions and business models on off-grid solutions, followed by mini- and micro-grid and grid-connected rooftop systems (RTS). Distributed energy sources, decentralized generation and stand-alone systems are often used interchangeably. The EA, 2003, has provisions for the framing of policies by the central government on stand-alone systems for rural areas and non-conventional energy systems (Section 4 of the EA, 2003). Stand-alone systems have been defined as systems involving the generation and distribution of electricity without connectivity to the grid. Similarly, there are provisions for the national-level policy on electrification and local distribution (Section 5). Emphasis has been laid on the use of local institutions such as panchayat institutions, non-governmental organizations, franchisees, user associations, cooperative societies for such decentralized generation and distribution. In fact, facilitative frameworks like license exemptions have also been provided for such ventures (Section 13, 8th Proviso to Section 14). For rural areas notified by the state government, distributed generation involving generation and distribution can be undertaken without the requirement of any license. This is meant to facilitate the ease of business in these areas. The Revised Tariff Policy (2016) makes special mention of micro-grids for rural areas where grid connectivity has not reached. It seeks to address the concerns of investors in the event of grid reaching such areas

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by mandating the purchase of such assets at a depreciated cost by the distribution licensees. Where do we stand in terms of the implementation of these visions? What are the international business models? How similar or different is India on the roll out of measures for distributed energy resources? We seek to explore these questions in this chapter.

Off-grid/Small Home Systems Over the past several years, there have been a number of initiatives in India and elsewhere, especially Africa, to supply electricity affordably to far-flung rural communities using RE technologies. The initial successes with these initiatives in East Africa offer hope for accessing clean and qualitatively superior energy to the people living in the sparsely populated rural areas of the developing world, at least for their lighting needs. One such business that has found significant success in East Africa is called pay-as-you-go (PAYG).2 The business model behind this approach was first developed in Kenya and subsequently spread to other countries in the region, namely Tanzania, Rwanda and Uganda. Affordability is the central feature of distributed RE-based PAYG business models. It is structured to eventually offer ownership of RE generation units to remotely located rural consumers through small and flexible repayments over a stipulated period, which is usually one to three years. The success of the model in Africa has been predicated on the fact that consumers do not have access to the state-wide large-scale electricity distribution networks for their lighting use since these areas are generally bypassed by bulk electricity distribution grids. Apart from lighting, rural consumers also use the electricity thus generated for charging their mobile phones. Enterprises in this business generally charge fixed down payments to consumers for the installation of solar panels and collect regular payments from them for the electricity consumed. Functionally, the model offers two options, either

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rent to own or energy service for a unit charge. The former is, however, more popular with consumers,3 as it allows them an ownership of the solar unit without hurting their pockets. The collection is usually in monthly instalments over a period of one to three years. Continuing post-ownership maintenance and service by enterprises helps to cultivate consumer confidence in the system. One very important aspect for the success of this model in East Africa has been the wider acceptance of the mobile payment via the M-Pesa platform. In fact, the aggressive joint marketing of solar panels with mobile network partners4 with the other features discussed above has led to the success of the PAYG business model in Kenya and the neighbouring countries. Thus, Kenya has now emerged as a matured market for distributed solar PV business. While lack of cheaper access to grid electricity in East Africa has made off-grid solar options attractive to consumers in rural areas, there is no such issue in India. The grid connectivity is far cheaper than in Africa. Besides, since 2018, grid connectivity in India has been provided to all villages. Thus, apparently, there seems to be little scope for marketing distributed energy solar systems to rural households. However, despite the 100 per cent electrification of the villages in India, it still remains a home to a large un-electrified population—as many as 100 million in fact.5 Even those rural households connected to the grid, the supply of electricity to them has been anaemic with frequent blackouts. This situation has created a commercial opportunity for private enterprises to profitably distribute PV solar kits to rural households for generating electricity for their needs. Thus, the PAYG opportunity seems to have come alive in India. One of the leading operators in India that has set the pace in this market is a privately held start-up called Simpa Networks. Despite several constraints to replicating the Kenyan model in India, this enterprise has made headway. The Simpa’s systems,

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in fact, act as a backup to the main grid, and most of its customers are those who can purchase and use inverters. Further, to overcome the constraints imposed on swift bill payments, by underdeveloped rural telephony markets in this country, Simpa Systems has overcome this hurdle by selling prepaid recharge packages based on the intended use of electricity that is provided by household solar home systems. When a customer makes the payment, a unique code is generated on his/her mobile phone. When this code is fed in the meter, it activates the solar system for a stipulated use for a period over which the payment lasts. To prevent the theft of electricity by any customer, Simpa has provided tamper-proof smart panels. Further, in the case of Simpa too, like the Kenyan enterprises, ownership is transferred after 28 months. Moreover, it offers additional advantages to consumers, like allowing them to stop payment if the unit is surplus to their needs or if the unit breaks, or when it is not adequately maintained. This builds trust in the enterprise as a reliable partner. To overcome the absence of a mobile money payment system in rural markets in India, Simpa hires authorized agents to sell prepaid credit cards to customers for cash. Thus, the comparison of the African approach to the Indian one reveals that both have many similarities. For example, both are strongly customer-centric; both have a convenient mode of periodic payments for services rendered; both transfer ownership of solar PV electricity generators to household consumers at the end of a stipulated period, after receiving a stream of regular payments over that period; in both cases, off-grid solar farms operate without government subsidies and, in India, more than half of them do not offer any financing arrangement to consumers. Further, in both cases, there is a strong focus on continuing regular maintenance even after the transfer of ownership and on providing prompt repair services. This, in fact, is what builds consumer confidence in the agencies supplying

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distributed solar PV systems. Also, enterprises in both cases have evolved default-free payment collection systems to stay afloat. However, the main differentiating aspect between the two business models has been the collection system. In East Africa, co-marketing with mobile payment companies has been a major factor in de-risking the business. In contrast, the absence of mobile money platforms in India has meant higher investments in the collection and distribution workforce by the Indian firms catering to these markets. While the business approach in both countries is largely focused on catering to the electricity demands of individual middle-class households, it leaves out a large chunk of the population that cannot afford the ownership of solar systems despite the liberal payment terms. For them, the micro-grids that distribute electricity across a larger number of consumers offer an affordable solution.

Micro-grid Apart from the initiatives to promote bulk-size solar plants and wind farms of similar capacities to states’/national grids, the Indian government has also been encouraging installations of distributed energy systems on a smaller scale. Broadly, the distributed segment of the RE generation is made up of two sub-segments: one consisting of scattered rural hamlets and the other of industrial units with expansive roofs from the consumer side. The rooftop installations offer the scope to harness solar energy commercially, both for captive consumption and for the supply to power grids for mass consumption. This sub-segment is discussed later in the chapter. First, we focus on stand-alone micro-grids as a means of commercially delivering electricity to small hamlets for their commercial (small shops) and residential needs.

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Thus far, the application of micro-grids has been at a pilot stage. Technically, DC micro-grids have been the preferred mode for distributing electricity to scattered hamlets which are situated at a distance from the main grids. Their choice has been dictated by the inherent advantages of the DC grid over the AC micro-grid.6 Although AC micro-grids have an inherent advantage over DC grids of being able to utilize prevalent grid technologies, protections and standards, the stability requirements of reactive power in their case override these advantages. DC micro-grids, on the other hand, provide an advantage of reliable, efficient and sustainable smart grids at a comparatively lower cost and greater effectiveness. Besides, DC micro-grids have better compatibility with DC storage and are more flexible and accommodating of load.7 While this may be the technical aspect of the energy delivery network, in recent years, solar PV systems have gained precedence over all other new and RE technologies in India; primarily for their operational simplicity, ease of maintenance as well as a fact that India is spatially well endowed with solar radiation across its land mass. Micro-grids have been principally designed to cater to the lighting and mobile-charging needs of rural households in India. There are at present four agencies engaged in promoting micro-grids, all of them operating mostly in the Indian state of Uttar Pradesh (UP). The Energy and Resources Institute (TERI) is an NGO; Uttar Pradesh New and Renewable Energy Development Agency (UPNEDA) is a state governmentpromoted agency; and there are two private players, Mera Gao Power (MGP) and Minda, an automobile company. Each of them has its own business model and organizational structure to match its operational requirements. UPNEDA, a government agency, operates as a single monolith, employing locals to perform various operational functions. It is entirely dependent on the government sources for its funds,

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either in the form of subsidy from the MNRE or the development funds allotted to it by the state government. TERI, on the other hand, operating on an NGO model, trains and develops local entrepreneurs whom it calls energy entrepreneurs (EE). Some among these entrepreneurs have been known to have funded their ventures entirely with their own funds. However, more generally, they fund their ventures partly with their own funds and balance them with subsidy from TERI. There are also some among them who have availed bank loans for funding their ventures. The two private agencies in the field, Minda and MGP, operate as micro-DISCOMs (distribution companies) and run their ventures as business propositions. Minda, however, after initial handholding, hands over its micro-grids to rural entrepreneurs after training them to run the micro-grid as a business. Generally, the micro-grids set up by these four categories have between 10 and 100 households attached to them. But TERI, an NGO, is known to have set up a grid with as many as 1,100 households connected to it. MGP has a prepaid billing system for supplying electricity to its consumers; Minda has devolved the revenue collection responsibility to rural solar entrepreneurs. In case of UPNEDA, this function is internalized, like the most government-owned DISCOMs, whereas in the case of TERI, EE who effectively are the owners of their business do so by themselves. Proper maintenance, operations and billing payment systems are key to consumer satisfaction and enrolment. The overall bill collection record of UPNEDA has been poor in comparison to the other three players in the field. Primarily, this is due to its poor operational performance in comparison to the other three, which have been operating their micro-grids quite efficiently. UPNEDA’s poor performance has also been the cause of its inability to retain consumers. Overall, the impact of micro-grids membership on the consumers’ purse has been positive. They were earlier using

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kerosene for their lighting requirements. After connecting with the micro-grids, they have been able to cut down their average monthly expenditure on lighting by as much as 68.4 per cent.8

Grid-connected Rooftop Solar Photovoltaic Systems Worldwide, the grid-connected PV rooftop solar power generation has been greatly successful in many countries. This success has been aided by the supportive regulatory framework provided by the governments of these countries. As assessed by the National Institute of Solar Energy, India’s power potential from rooftop solar PV source has been estimated at 42.8 GW. To tap this potential, there has been a drive in India too towards encouraging investments in rooftop solar PV panels. However, despite the increasing emphasis on promoting power generation from this source, the progress has been slow here. Table 4.1 provides the cumulative growth of rooftop solar PV installations since 2015. Although the annual growth in rooftop solar PV power generation capacity in India, as observed from Table 4.1, seems to have been steep, but when seen against the national potential, it is evident that it would take several decades to achieve this potential. At the beginning of the present decade, when interest in solar rooftop PV segment began to grow, it was promoted principally as an opportunity that commercial and industrial units could exploit for their captive power consumption. Accordingly, the

The Year-wise Cumulative Solar Power Rooftop Table 4.1  PV Installations (2015 to 2018 February)9 31 March 2015

31 March 2016

31 March 2017

2 February 2018

41 MW

241 MW

656 MW

953 MW

Source: Standing Committee on Energy, Sixteenth Lok Sabha.

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Forum of Regulators (FOR) made up of electricity regulators from the Indian states and the union territories (UTs) evolved a Model Net Metering Regulation (NEM 2013)10 in 2013 in order to promote this form of generation to electricity consumers. However, this regulation soon ran out of its usefulness. Based on the international experience, as it was recognized that the available space on the rooftops offered the opportunity not only for harnessing solar radiations for generating electricity for captive consumption by the units owning these premises but also for power supply to a wider market consisting of the states’ power grids. This broadened scope called for having a fresh look at the NEM 2013 by the FOR. In 2014, when the Government of India (GOI) set an ambitious target of 40 GW for the grid-connected rooftop photovoltaic (GRPV) installations in the country to be achieved by the year 2022, it became necessary for the MNRE to reassess the adequacy of the prevailing regulation. Accordingly, it undertook a review of the existing Metering Regulations and Accounting Framework for GRPV installations with the assistance from the World Bank and the State Bank of India. The report found several lacunae; some related to technical aspects, some to commercial aspects and still others of a miscellaneous nature. These are summarized here.11 Gaps related to technical aspects included restrictions in terms of individual capacity based on sanctioned load and maximum GRPV capacity; different limits on GRPV capacities connected to distribution transformer (DT); limited provisions on real-time monitoring of solar generation and participation in system operations in the case of large penetration of the GRPV system. Gaps related to commercial aspects included limited business model options available to consumers and developers, and limited scope for DISCOMs in the present scenario; absence of additional clauses related to change in ownership and flexibility in existing power purchase agreement (PPA)/connection

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agreement; no remuneration for excess generation in present energy accounting and commercial settlement principles. Gaps related to other aspects include general definition, metering and communications. The definition of premises and solar rooftop PV systems needed to be reviewed to provide greater visibility on solar generation to DISCOMs and systems operations; metering and communication requirements needed to be reviewed to provide greater visibility on solar generation to DISCOMs and system operators. These findings in the above-mentioned report provided the basis for upgrading the NEM 2013 to match the changed emphasis on the promotion of GRPV. In the previous Model Regulations (NEM 2013), considering that the one-way flow of power was a limiting factor on distribution systems with a capacity of 33 KV and below, an aggregate capacity that could be connected to such systems was limited to 15 per cent of the peak capacity of the DTs. A further limit had been added to prevent the load on the system from exceeding 1 MW. Based on this, the SERCs passed their own regulations for their jurisdictions. They restricted the GRPV installations of individual customers, specifying varying percentages (ranging from 15% to 75% of the DT loading) of their sanctioned or connected to loads. Some, in fact, went as far as stipulating capacities even higher than 50 per cent of the DT load. While this was the case earlier, it was found based on international experience in 48 countries that the growth of the GRPV segment could be given fillip by delinking the capacity restrictions on the installations from their respective DT capacities. What this meant in the Indian context was that there was scope for installations of systems of higher GRPV capacities, after considering the operational requirements of distribution systems and incorporating adequate measures warranted by these requirements. Accordingly, the New Model Regulation provided for the following.

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New Model Regulations The New Model Regulation12 stipulates that when the sanctioned solar generation capacity is not more than the sanctioned load or contract demand, the aggregate PV power plant capacity can be set up as high as 100 per cent of the DT capacity, even under the worst-case scenario, that is, 0 per cent running load, considering feeder’s thermal capacity as the deciding factor. However, when the RE-based generation capacity is not controlled on the basis of the sanctioned load of the respective DT, the aggregate or single PV power plant capacity that can be connected to the network, it has to be decided case by case based on the loading of the respective DT, after taking into account the over voltage at the point of common coupling as a deciding factor. Thus, the upper limit on connecting DRE system to a feeder or a DT was recommended to be 100 per cent of the respective feeder or DT. Further, the Model Regulation has considered two types of systems and stipulated separate limits on the capacities that can be connected in each case. In the first case, where the capacity is linked to the sanctioned load, ‘it shall not exceed the sanctioned load/contract demand of a consumer’. Under this, the minimum 1 KW and 10 KW-size systems can be set up under net metering and billing systems. In the second case, the maximum capacity of the independently DRE systems at any particular location that can be installed is linked to the capacity and configuration of the electricity system and the power flows that the DRE system may cause. Here, the maximum capacity that can be installed is stipulated as 50 KW. Further, taking into account the online monitoring, inspection and billing requirements, the New Model Regulation has provided for the installation of advanced metering

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infrastructure with RS-485 or higher communication port for all meters in the light of the planned future digitalization of the grid. The criteria for participating in rooftop solar business have also been expanded with a view to encouraging greater participation, thus opening the opportunities for DISCOMs and other entities. Changes have also been made in PPA and connection agreements incorporating greater flexibility than before. Previously, owners of captive rooftop solar PV systems were not paid for any excess generation over and above their own requirements. Under the new framework, there is a provision for the settlement of excess energy procured by distribution licensees at their average power purchase cost (APPC) of the energy procured from all sources. Earlier, some states were liberally allowing installations on open and elevated land under the rooftop category. This conflicted with NEM 2013’s definition of rooftop. In the new model, this issue has been resolved by linking DRE capacity to either sanctioned load or systems’ constraints, in sync with consumer demand and within the safe limits of grid operations. However, the definition of premises as provided in for in the EA, 2003, has been retained. As for compliance towards renewable purchase obligation (RPO), the committee that presided over the drafting of the New Model Regulation has recommended to suitably incorporate the provision for crediting gross generation from rooftop solar projects to DISCOMs towards meeting their solar RPO targets, so as to ensure uniform application across the country.13 Further, the recommendation is that the quantum of electricity generated by captive units harbouring solar PV systems over their rooftops, which are under net metering arrangement should, if such consumers are not the obligated entities, qualify towards meeting the solar RPO of the distribution licensees. On the other hand, in the case of obligated entities, the quantum of electricity consumed by these entities from their rooftop

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solar PV systems, under the net metering arrangement, would qualify towards their own RPO compliance. However, in the case of obligated entities, these units would have to install, at their own cost, a solar generation meter conforming to the applicable CEA Regulations, at an appropriate location, to measure the energy generated from the solar PV systems at their rooftops, if they want such energy generation to be counted towards meeting their RPO commitments. As far as the costs of installing meters at non-obligated rooftop generators sites are concerned, these costs are to be borne by the distribution licensees if they desire that such energy generation should be counted towards their RPO compliance. A solar generation meter at the location, in such cases, must conform to the applicable CEA Regulations for measuring the energy generation from the rooftop PV system. Further, the Model Regulation requires that the distribution licensees maintain solar generation meters at their own costs. Several SERCs and UTs have since adopted the model in their jurisdiction.

New and Emerging Concept of Peer-to-peer Trading Peer-to-peer (P2P) trading is an emerging business model in the landscape of distributed energy resources. It enables trade of electricity between prosumers (i.e., consumers who are also producers of electricity, e.g., consumers owning rooftop solar systems) and consumers. For instance, two or more neighbours can agree on an arrangement for the sale and purchase of electricity at a mutually agreed price without any intermediary. A consumer or a group of consumers owning rooftop solar panels can sell surplus power to another group of consumers and save costs. It could be a win-win situation for both. For RTS owner, additional revenue could reduce the payback period of his/her investment and could result in lower electricity cost for the buying consumer. The low cost is on account of the

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avoidance of cost towards the transmission and distribution of electricity and associated losses, which are generally associated with the traditional system of electricity generated from a generating station, which is then transmitted and distributed before reaching the end consumer. This business model has the potential of empowering consumers and encouraging investment in the renewable segment. It provides an interconnected online marketplace for consumers. A number of pilot schemes have been in operation in countries such as the USA, the UK, Germany, Bangladesh, Colombia and the Netherlands.14 Interestingly, in India, UP has in the recent past (December 2019) initiated a pilot on P2P transaction of RE. UP ERC approved a proposal from the distribution licensee, namely Uttar Pradesh Power Corporation Limited and UPNEDA to implement a solar-based P2P trading pilot using block chain technology. Initially, government buildings/consumers shall form the peers for the pilot project.15 Finally, while UP’s initiative is encouraging, the fact remains that, in general, DISCOMs are reluctant to let go their highend consumers for solar rooftop installations. The captive consumption of electricity generated from their rooftop solar PV-generating units displaces the equivalent energy that they would have otherwise sourced from the DISCOMs. This would shrink their revenues and, in turn, dent their ability to crosssubsidize low-end consumers. However, this is a larger issue that requires implementing the stipulations in the EA, 2003, which requires utilities to phase out cross-subsidies over a specific period of time. This stipulation had been incorporated in the Act to stop political interference in the commercial operations of power utilities with a view to restoring their financial health. Reportedly, the DISCOMs have been reeling under huge debts from unpaid dues of power-generating companies, which has been affecting the overall health of this sector. Hence, it is high time that, as

56  Renewable Energy in India

required by the EA, 2003, the DISCOMs were spared of having to cross-subsidize low-end consumers. This could be a better panacea than curbing the growth of rooftop solar generation in order to safeguard the DISCOMs’ financial health.

Chapter Conclusion Official claims notwithstanding, a substantial portion of households in India still do not have access to energy. Taking the grid to remote areas is not only cost prohibitive but also non-sustainable in terms of quantity as well quality of supply. The DISCOMs whose finances are already in the red do not have inherent interest in supplying electricity to such areas because non-remunerative tariff for the supply of electricity in these areas further strains their finances. It is, therefore, imperative that business models supporting distributed energy systems and seeking to harness locally available renewable resources are encouraged. The financial health of the DISCOMs and the distorted tariff structure also come in the way of supporting distributed energy sources like rooftop solar PV projects. The subsiding consumers, mostly in urban areas, opt for such systems and the DISCOMs resent because a reduction of demand from such consumers upon their installation of rooftop solar PV systems leads to irreparable revenue loss for them. The solution therefore lies in larger tariff reforms, by way of tariff rationalization, so as to address the constraints of distributed energy systems. Having dealt with policy initiatives for the promotion of large-scale renewable in the previous chapter and small-scale distributed energy systems in this chapter, the next chapter and subsequent chapters present a detailed analysis of core policy and regulatory interventions, namely RE pricing, RPO and market mechanisms like renewable energy certificate (REC) and the overall market design for renewable. Discussions in these chapters are central to the theme of this book besides the findings and recommendations in the last chapter.

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Notes 1. http://energy.mit.edu/wp-content/uploads/2016/12/Utility-ofthe-Future-Full-Report.pdf (accessed on 16 November 2020). 2. Prabhakar Yadav, Anthony P. Heynen and Debajit Palit, ‘PayAs-You-Go Financing: A Model for Viable and Widespread Deployment of Solar Home Systems in Rural India’ (2019). Available at https://www.sciencedirect.com/science/article/pii/ S0973082618309839?via%3Dihub (accessed on 9 February 2021). 3. Ibid., 142. 4. Ibid., 140. 5. Ibid., 146. 6. Debajit Palit and Sangeeta Malhotra, ‘Energizing Rural India Using Micro Grids: The Case of Solar DC Micro-grids in Uttar Pradesh State, India’ (Conference Paper. New Delhi: The Energy and Resources Institute, 2015). Available at https://www.researchgate. net/publication/271964221_Energizing_rural_India_using_micro_ grids_The_case_of_solar_DC_micro-grids_in_Uttar_Pradesh_State_ India (accessed on 9 February 2021). 7. Ibid. 8. Ibid. 9. Standing Committee on Energy, Sixteenth Lok Sabha, ‘Action Taken on the Recommendations Contained in the TwentySecond Report (16th Lok Sabha) on Energy Access in India— Review of Current Status and Role of Renewable Energy’ (New Delhi: Lok Sabha Secretariat, 2017–2018), 33. Available at http://164.100.60.131/lsscommittee/Energy/16_Energy_36.pdf (accessed on 9 February 2021). 10. http://forumofregulators.gov.in/Data/Working_Groups/Net.pdf (accessed on 9 February 2021). 11. Forum of Regulators, ‘Report on Metering Regulation and Accounting Framework for GRID Connected Rooftop Solar PV in India’ (2019). Available at http://www.forumofregulators.gov. in/Data/Reports/REPORT-METERING-ROOFTOP-08-05-19.pdf (accessed on 9 February 2021). 12. Ibid. 13. Forum of Regulators, ‘First Report of FOR Technical Committee on Implementation of Framework for Renewables at the State Level’, Volume I (Covering Proceedings: December 2015–November 2017), 23. Available at https://energyexemplar.com/wp-content/ uploads/Implementation-of-Framework.pdf (accessed on 9 February 2021).

58  Renewable Energy in India

14. https://www.irena.org/-/media/Files/IRENA/Agency/Publication/ 2020/Jul/IRENA_Peer-to-peer_trading_2020.pdf?la=en&hash=D3E25A5BBA6FAC15B9C193F64CA3 C8CBFE3F6F41 (accessed on 17 November 2020). 15. https://uperc.org/App_File/Pt-no-1522of2019UPNEDA-02–122019-pdf122201951425PM.pdf (accessed on 17 November 2020).

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5

Renewable Energy Pricing in India What Is Missing?

Introduction Pricing has all along been at the centre stage of the discussion in the context of the development of RE. In the major economies of the world, fixed price support is extended as supply side push for renewable, which in a way obviates the need for RPO as a demand-side support. In others, RPS—a combination of RPO and REC mechanism—is adopted as a support mechanism for the promotion of RE. The RPS system does not provide fixed price support as renewable projects under this scheme are expected to participate in the wholesale market for the sale of their electricity components. The unique distinction of India lies in the fact that the country has used all three instruments, namely fixed price, RPO and REC mechanism, for the encouragement of renewable. This chapter covers the pricing aspect, while the next chapter focuses on

RPO, and the following chapter discusses the REC framework in the Indian context. As regards the pricing of renewable, there are two broad approaches, namely the cost-plus approach of the tariff determination by the regulator and the competitive approach of discovering price through auction. The question as to whether auction as a method of price discovery is suitable for intermittent RE sources such as wind and solar has been and continues to be a subject of debate. Proponents of cost-plus approach argue that, given the uncertainties around the availability and variability of wind and solar resources, there are likely chances of projections going wrong, thereby making auction a tenuous exercise fraught with risk. The advocates of competition argue, on the other hand, that auction is the only way of discovering the efficient cost of such installations. In so far as uncertainties and variability are concerned, these aspects can be suitably addressed in the auction design through equitable allocation of risks between the project developers and the buyers. They also argue that competitive bidding has the advantage of inducing technological and operational improvements, in that the bidders are impelled to invest more in better technology and forecasting techniques to minimize the risks arising out of variability. India has experimented with both cost-plus approach and auction for soliciting renewable project proposals. Several states in India still determine cost-plus tariff for wind and solar while, at the national level, auction has of late become the norm for setting up wind and solar projects. An important point to note here is that, whether cost-plus or auction, the tariff so arrived remains fixed generally over the useful life of the project, thereby providing long-term certainty for investors. This chapter deals with both of these methods of tariff determination for renewable with all their nuances. This discussion is critical not only from the point of view of understating the cost and operational dynamics of variable RE but also for appreciating the debate around the future market design for renewable discussed at length in a later chapter.

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Cost-plus Approach In India, the preferential tariff for renewable technologies is fixed based on the cost-plus formula. It involves the calculation of tariffs by the scrutiny of project costs. While scrutinizing costs, any concession and tax exemptions availed by promoters are factored in. The tariffs so derived are believed to provide equitable financial returns to developers while simultaneously avoiding unsustainable burden on consumers. As explained in the previous chapters, the decision to use the ‘cost-plus’ approach in determining preferential tariffs for renewable power has been justified with the following explanation: while LRMC and the avoided cost of generation give the correct economic signals, in today’s context, it is not possible to arrive at the correct estimates of these numbers; RE technologies have a small share in energy generation in comparison to conventional energy sources; as the price of generation from conventional sources—which forms a major chunk of the total power supply— is not giving any meaningful economic signal, application of economic principles to pricing electricity from RE technologies operating on the fringe is unlikely to have any significant impact on the generation market; cost-plus methodology allows investors to earn reasonable returns commensurate with the risks borne by them; it provides a degree of certainty to revenue which, in turn, makes the financing of these projects feasible for investors; since technology is still evolving, rapid reduction in prices of equipment is likely, and periodic review under the ‘cost-plus methodology’ would allow review of cost elements at regular intervals and factor in the advances in technology while deciding tariffs for new renewable projects in future. Given this explanation, the capital cost is a starting point of determining the preferential tariffs for renewable power projects. The CERC at the centre determines the tariffs for central government-owned and interstate power-generating companies. The SERCs do so for generating companies in states. The unique feature of this exercise at the centre is the capital cost benchmarking for different renewable technologies. 62  Renewable Energy in India

The CERC has undertaken this exercise—first for the threeyear period from 2009–2012; subsequently for the five-year period 2012–2017; thereafter for three years from 2017–2020 and currently for 2020–2023. One may well ask here: of what use is this exercise when the market for renewable power is moving in the direction of a market-determined supply, demand and prices? To answer this, though there has been an initiative towards letting the market to determine prices, the preferential tariff option has not been taken off the table yet. Also, limits have been placed upon the prices of RECs. To prevent a free fall, the floor prices still have to be determined after due consideration to the fair return on equity to the renewable power developers. Since the return on equity has to be calculated on the capital costs of renewable power projects, it is important that these costs are properly and transparently benchmarked.

General Approach to Capital Cost Benchmarking Generally, under the regulatory regime of tariff determination in India, capital costs form the most critical element in regulated tariffs. This assumes even more significance and a daunting task in the case of RE projects. The norms based on a ‘sample representative case have to be developed, after taking into consideration the diversity of sites/state specific parameters, the variations in technological applications and a range of unit sizes supplied by multiple suppliers’. The issue here is how to standardize the approach for the sake of greater uniformity and consistency. To begin with the task of capital cost benchmarking, various approaches for developing benchmark capital costs—for different RE technologies—are evaluated. The following approaches have been considered by the CERC while arriving at the benchmark capital costs for RE technologies, namely regulatory approach, market-based approach, actual project cost approach and international project cost-based approach.

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Regulatory Approach In this approach, capital cost benchmarking is done based on comparisons of existing capital cost norms, as approved by various SERCs. ‘Pooled Capital Cost’ (` Cr/MW) of RE capacity added during the previous three to five years is used as the basis for the trend analysis of capital costs for arriving at the benchmark. There are, however, issues around this approach. SERCs do not generally consider year-on-year variations while estimating capital costs for the control period. They assume that a project commissioned at the beginning of a control period would have the same capital costs as that commissioned at the end of it. It is seen as a major shortcoming as it leaves out the effect of annual inflation on the capital costs of renewable projects. While inflation may not significantly affect the tariff over a short period, if the inflation rate in equipment costs is low, it indeed would were this rate to accelerate. Irrespective of whether such fine-tuning is essential or not, one can argue that it would be appropriate to consider this aspect in capital benchmarking right from the start (given a fact that the economy has seen bouts of high and low inflation over different periods of time), provided that the cost of information is not very high. The other failing of this approach is that, in most cases, the capital cost and other cost norms have been seen to be approved on the basis of claims in the detailed project reports of manufacturers and developers that have been submitted to the state commissions. This raises the issue of reliance on the ‘interested party’ data. This absence of an independent source in the evolving norms for capital costs is, of course, a matter of concern. To press a point further, there have been very few instances where projectspecific parameters, such as unit size and technology, have been given due consideration in arriving at capital cost norms. This lacuna needs addressing.

64  Renewable Energy in India

Market-based Approach The market-based approach carries out the comparison of capital costs for RE projects that have been awarded on the basis of a competitive bidding process by public and private entities. This is true particularly of the wind power projects. The tender conditions for these projects are examined to evaluate the scope of supply and services over a period of three to five years. The per unit capital cost norm, expressed as ` Cr/MW, for the capacities thus awarded for the units of various sizes, locations and by manufacturers/suppliers, is collated. Using this information, trend analysis is undertaken. This approach too has limitations. The scope of supply and services stipulated in the tenders varies widely. For example, in some cases, the bidder is expected to provide services that include identification of sites, project clearances and O&M services but, in other cases, this is omitted. Moreover, for capital cost benchmarking, the components of capital costs should be segregated and shown separately; this break-up by costs is not always easily available. Further, since the market-based approach provides information about the capital costs of projects that have been cleared through the competitive bidding route, one would expect these costs to reflect the real costs of capacity additions rather than the notional costs (as assumed in the regulatory approach). However, there are only a limited number of equipment manufacturers in each renewable category. This approach may hence not be truly reflective of the competitive capital costs if there is collusion in bidding.

Actual Project Cost-based Approach In actual cost-based approach, an analysis of capital costs for projects commissioned during a certain period in the recent past is undertaken. The information is furnished by the project developers as part of the project appraisal requirement to various financial institutions (FIs)/banks or United Nations

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Framework Convention on Climate Change, either for availing loan or for registration under CDM benefits. The project cost data from these sources are obtained from their websites and analysed for arriving at the capital cost benchmarks. To elaborate, various elements of capital costs—spanning plant and machinery costs, erection and commissioning costs, expenditure on preparation of land and civil works, and financing costs, like the interest during construction period—are evaluated. Finally, in arriving at the benchmark capital costs, a trend analysis in terms of movement of overall capital costs (` Cr/MW) and its components is undertaken for the duration of previous three to five years.

International Project Cost Approach In countries such as Germany, Denmark, the USA and a few others, renewable sources-based energy generation constitutes a significant part of their total energy requirement. Several studies have been conducted in these countries, covering various aspects of RE equipment procurement and installation costs, generation costs and socio-economic costs. As observed by these studies, plant and equipment costs have not varied significantly between countries. This is largely owing to the fact that the raw material/equipment costs in these countries have been more or less uniformly influenced by international market prices and not by the domestic situation. Based on this finding, equipment costs across these countries could be a good guide to benchmarking capital costs for renewable projects in India. However, the capital cost for RE projects is also influenced in some cases by the local factors, like the subsidy to protect domestic manufacturers from international competition or the fluctuations in exchange rates. There could thus be significant differences when comparisons of capital costs of RE projects between well-developed and emerging or developing economies are made. In the Indian context, there is a reason to believe that benchmarking based on such studies

66  Renewable Energy in India

would have only a limited relevance for evolving benchmarks for RE projects. Pertinently, the CERC has of late dispensed with capital cost benchmarking for wind and solar projects, as competition has taken roots in these segments. For other technologies, the benchmark cost is arrived based on the approaches discussed in the preceding section, but insufficient data base still constrains the exercise. For the current control period of 2020–2023, the benchmark capital costs of the previous control period of 2017– 2020 for most renewable technologies have been retained.1 Further, the Regulations provide that the capital costs of the first year of the control period shall continue to apply in subsequent years, unless reviewed by the Commission. This raises a question mark on the efficacy of the capital cost benchmarking exercise. However, the focus of this book being on wind and solar, and given that capital cost benchmarking is not undertaken for these technologies at the centre by the CERC, further discussion on this aspect is not considered necessary. Before departing, it would be relevant to highlight that the determination of capital cost and the cost-plus tariff is still prevalent at the state level. In this exercise of the tariff determination, after the benchmark capital cost is arrived, a normative debt–equity ratio of 70:30 is applied treating 70 per cent of the capital cost as a loan and 30 per cent as an equity. Thereafter, financial norms, namely interest on loan, interest on working capital, return on equity, operation and maintenance (O&M) cost and depreciation are used to arrive at the tariff. The first-year tariff is escalated at predetermined rate of escalation and then a discounting factor equivalent to the weighted average cost of capital is applied to determine the levelized tariff. A comparison of the tariffs so determined by the State Commissions (Appendix 5A) with the tariffs discovered through auction (Appendices 5B and 5C) reveals a distinct edge of the latter (bid tariff) over the former (regulated tariff). Therefore, a natural shift towards auction as a price discovery for wind and solar projects is likely in the future.

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However, there is one school of thought that believes that it is too early to conclude that auction is superior to cost-plus. With the emerging trend of aggressive bidding, especially in the e-reverse auction (eRA), long-term viability of such projects remains a question. This is corroborated by the large number of cases filed before regulators seeking an extension of the commercial date of operation under the force majeure clause of the PPA and requesting compensation in terms of Change in Law clause of the PPA. The counterargument, on the other hand, is that bid prices are aggressive because competition has induced cost efficiency and the bidders have been able to economize on cost of debt, depreciation and also have lower expectation of return on equity compared to the cost-plus dispensation. The auction process being at infancy, any discussion on efficacy in terms of the actual deployment of projects under the bidding route versus cost-plus route would be premature at this stage. What may be relevant is a discussion on the auction design itself. The next section accordingly analyses the recent initiatives on auction design against the background of international developments in this field.

Auction Auction theory has been the basis of much fundamental theoretical work: it has been important in developing our understanding of other methods of price formation, for example, negotiations in which both the buyer and the seller are actively involved in determining price. As discussed so far, one of the most important issues facing Indian electricity regulators has been the pricing of electricity generated from grid-connected renewable energy sources, especially from wind and solar power farms, which have been the main thrust areas of the Indian government’s RE policy. Over the years, there has been an ongoing debate on the practical applicability of applying marginal cost pricing to electricity

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generated from RE resources in India, as discussed earlier in the book. The importance of the economy-wide marginal cost pricing stems from a fact that it ensures the efficient functioning of a market economy as defined by the state of general equilibrium. An economy in general equilibrium ensures that the interests of all its participants are well balanced and, therefore, satisfactory. Although market-driven prices fully aggregate all of economy’s information (Paul Klemperer, pp24) and hence reduce the cost of decision-making process for all its participants to almost zero, this may not necessarily be true in all situations, especially when market power between participants is imbalanced. The marginal cost pricing offers a solution in such situations to balance an imbalanced system. To deal with situations where estimating marginal costs administratively has not been easy, governments worldwide have turned to auctioning as an instrument to achieve this. However, while auctions may resolve the practical problems associated with marginal cost pricing, it is moot whether they also lead to competitive pricing of resources, unless they are carefully designed. In this chapter, we set out to assess the effectiveness of the auctioning method adopted in India in the pricing of renewable resources. But, for that, we first provide an overview of how auctions work and their economic usefulness.

Overview There has been a considerable effort by economists to find the economic basis for auctions and to examine the conditions that lead to optimal auctions. There are four standard types of auctions that are generally deployed for discovering the price of objects of economic value, namely the ascending bid auctions, the descending bid auctions, the first-price sealed-bid auctions and the second-price sealed-bid auctions. Of these, the sealed-bid auctions are most commonly used by governments for identifying suppliers for their requirements.

Renewable Energy Pricing in India  69

In first-price sealed-bid auction, each bidder independently submits a single-sealed bid, without seeing others’ bids. When bids are opened, the object is sold to a bidder whose bid price is the highest. In a second-price sealed-bid auction, though the process is the same, the winning bidder pays only the price that has been bid by a runner-up bidder for the object under auction. The ascending and descending bid auctions, on the other hand, are open bid auctions, where the auctioneer calls the price. In the former, bidding starts at a low price and keeps progressing to higher prices until a winning bidder is found. In this auction, bidders bidding low prices are left out of the running at every stage as the auction progresses and the price moves up. This process continues until the highest bidder is found. The descending bid, on the other hand, starts with an auctioneer announcing a very high bid price and successively bringing it down until one of the many bidders’ calls the price and wins the auction. With this, the auction ends and the winning bidder pays the price. In all of these auctions, the highest price bidder wins the bid. In contrast, in eRA, which is being used by the Indian government for auctioning the rights to develop wind and solar resources for producing electricity, the winners are the lowest price bidders. However, as far as project developers are concerned, their project valuation depends on their future net cash inflows determined by the difference between their future gross cash inflows and outflows discounted at the prevailing interest rate. Hence, those bidders with the highest project valuation would be expected to bid the lowest unit electricity price to win the bid. This unit price, which emerges from the reverse bidding process, is comparable to the LRMC, which is the preferred mode of pricing unit of electricity, as discussed in an earlier chapter of the book. In designing an auction, understanding the value structure of participating bidders is crucial for achieving auction goals by a seller (or a buyer in the present case, where the government can be seen to represent the electricity consumers). The bidders’ 70  Renewable Energy in India

signals in any auction depend upon their value function, which in turn depends on the nature of the information they possess; for example, in private value model, each bidder decides to bid a price for a concerned object of economic or psychological value, solely on the basis of his/her value function, which is distinct from others in the run. What it means in this case is that bidders place greater confidence on their own information than on information of other bidders and hence are unlikely to modify their bids even when others’ values are known to them. On the other hand, in a common value model too, each bidder has his/her distinct private information concerning the object under auction that may not be the same as its actual value, which is same for all bidders but not known to any of them. This is usually the situation in auctions of most underground mineral resources. In such cases, each bidder is prone to revising his/her value, when the values placed by other bidders are revealed during the auction process. However, one can think of a general model of value in which the above two cases are just the special cases of a larger set of values. For greater clarity on the matter, the reader can see Note 2.2 Incorporating the bidders’ value function in standard auctions helps in designing appropriate auctions that lead to achieving auctioneers’ objectives more effectively (ibid pp 6). A significance of what has been said lies in a fact that a good auction design promotes both efficient assignments of rights and competitive revenues for the seller. Hence, the structure of bidder preferences and a degree of competition are key factors in determining the best design. Each of the standard auctions has its merits and demerits. For that reason, which is the best for a particular situation depends on the overall complexity stemming from the nature of the economic object under auction, the auctioneers’ objectives, the bidders’ response functions, the actual and private perceived values of an object under auction and the risk preferences of the participants in auction. To evaluate the merit of an auction design, one needs an economic framework to assess this.

Renewable Energy Pricing in India  71

Revenue Equivalence Theorem (Peter Cramton, pp4) Auctions vary in complexity; the simplest being the first-price sealed-bid auction and the package clock auction (Ausubel et al. 2006; Cramton 2009) being the most complex of the lot. Between them, there are several of varying complexities. In the context of wind and solar power projects, only the first-price sealed-bid auction or, for that matter its corollary, the lowestprice sealed-bid auction is relevant here. A revenue equivalence theorem first postulated by W. Vickrey in 1961 provided the most important results for assessing the efficiency of the standard auctions. The theorem postulates that, in a single-item auction, all four elementary standard auctions (first-price sealed-bid, second-price sealed-bid, ascending and descending auctions) mentioned earlier result in the same expected revenue for the auctioneer while maximizing revenues among all four standard trading mechanisms when the seller has set an appropriate reserve price for an object being auctioned. This result applies to both private value models and common value models. A fact that the revenue optimization is here defined purely in terms of auctioneer’s revenue and not the bidder’s benefits is a contentious issue which is discussed later, with reference to the different stages of the eRA employed by the Solar Energy Corporation of India (SECI), for auctioning rights for development of wind and solar power resources across India. Notwithstanding this observation, the revenue equivalence theorem is now a standard reference point across the world for analysing and designing optimal auctions.

The Auction Mechanism Deployed in India for Dispensing Development Rights to Competing RE Power Developers The assumptions required for revenue equivalence are quite special (Peter Cramton, pp4), namely a single-item auction, 72  Renewable Energy in India

an independent private value function, risk-neutral bidders, an exogenous number of bidders, no collusion and symmetric bidders (i.e., the bidders appear identical aside from their private value information). In practice, these assumptions do not hold together. However, Myerson (1981) and Riley and Samuelson (1981) have showed that Vickrey’s results about the equivalence in the expected revenue of the different auctions apply very generally. Thus, even by relaxing these assumptions, it is possible to show that the revenue equivalence holds even for non-standard auctions, leading to optimum outcomes. On the basis of this, one could ask, where does the eRA stand in terms of optimality and also overall efficiency in the context of a broader economy? The MNRE spelled out the guidelines for tariff-based bidding process for solar and wind power projects in 2017 and appointed the SECI as a nodal agency for conducting eRAs for the selection of applicants for developing bulk power solar and wind farms in India. From among the bidding developers, those wining the reverse bids would be required to sell the electricity they generate to the RPO-obligated states upon completion of their projects (IIM Study pp 12). It may be noted that the selection of RE power developers under eRAs is directly related to the states’ meeting their RPO obligations. This raises questions about the future viability of the REC trading mechanism. However, we suspend further discussion on this to the concluding chapter. On examining the guidelines for any prohibitive clauses with respect to competition and restrictive bidding environment impeding free and fair international competition, an IIM study commissioned by the MNRE found the bidding methodology and evaluation process to be quite robust and transparent (IIM Study pp27). As per this study, low-entry barriers had encouraged new bidders to join in the fray and expanded competition. However, in the reverse auctions (RAs) conducted so far, there have been about 12 to 15 bidders at any one time and, on average, around eight qualifying from among them to enter the next e-reverse stage. An interesting finding of the Renewable Energy Pricing in India  73

aforementioned study is that there has been an increase in global financial institutionally backed aggressive bidders, with inadequate understanding of the peculiarities of the Indian energy market. These bidders, bidding aggressively in eRAs, have frequently found themselves trapped in technicalities at the project execution stage; particularly with respect to getting connectivity approvals from the Power Grid Corporation of India Limited.

e-Reverse Auction So what constitutes an eRA and how effective has it been in fulfilling the objectives of the nodal agency, the SECI, which conducts these auctions? In the simplest form of eRA, the buyer selects a supplier for supplying a range of products and services from a list of pre-qualified developers by employing the online bidding process. The bidders in this auction get to see each other’s bid values during the bidding process and adjust their own values downwards, if they feel necessary, to remain in contention. The process continues until a lowest price bid emerges. The contract is thus finally awarded to the lowest price bidder. On comparisons with the standard auctions, the eRA design followed by the SECI in India, though not exactly the same as that recommended by Klemperer (1998), is broadly similar. The bidding process is conducted in two stages. The first stage is a sealed-online bid that can be thought of as a version of the clock stage. The tender applicants who have met the prior mentioned technical and financial requirements in the ‘request for selection (RFS)‘ documents qualify to bid at this stage. These pre-qualified developers have to bid in an online sealed envelope below the ceiling price specified in the RFS document, mentioning the wind or solar power capacity they wish to undertake to develop at their bid price. The sealed envelopes containing the bidding information are opened online on a specified date mentioned in the tender. The bids are then ranked, starting with the lowest price

74  Renewable Energy in India

bid at the top and the higher priced ones sequentially in the lower ranks. The bidders in the lowest price range, whose bid capacities add up to the size of the tender, move to the next bidding stage, which is the eRA. Usually, the RFS specifies a certain minimum project size in multiple of which bidders must submit their share of the total tender capacity that they wish to develop at their price. In the second stage, the eRA is executed with bidders who have qualified from the first (sealed e-auction) stage. The price quoted by them in their individual sealed bids at the previous stage forms their individual ceiling price and they cannot bid above this price at the RA stage. The initial session at the eRA lasts an hour. During this period, bidders respond online to each other’s bids frequently. While bid prices are visible to participants in this stage, their individual identities remain concealed. This is to prevent any collusion between them during the auction. At the end of the hour, bids are ranked by the same procedure as in the first stage. Those who have quoted prices above the lowest price range that has emerged from this session are then given yet another opportunity to improve their bids in further 10-minute slots of reverse bidding to get back into contention. These 10-minute slots are repeated over and over again until prices stabilize at their lowest value, with no further prospect of improvement. The winning bidders thus found are finally awarded the right to develop the RE power as per their share committed at the sealed-bid e-auction stage (the first stage). A significant aspect in these auctions is that the value functions of the participating companies seem to be based on commonly available sets of information (such as the India Meteorological Department, National Institute of Wind Energy, for both wind and solar potential, National Renewable Energy Laboratory and some private firms specializing in collecting this information) on the one hand and, on the other, on a set of information specific to them.

Renewable Energy Pricing in India  75

It has been shown that the eRA can be made consistent with the revenue equivalence theorem. In fact, an experimental research on game theoretic approach has shown that there is almost no difference in revenue outcomes between the variant of the first-price sealed-bid auction, which is apparently deployed by the SECI at the first stage of its eRA, and the latter stage of the eRA, when participants are experienced bidders.3 Equally, they have found that there is ‘no substantial or statistically significant evidence of price difference between the last round of the open reverse e-auctions and the initial firstprice e-sealed-bids’.4 Practically, in the Indian context too, it has been observed that the second-stage eRA at best improves the final bid price of RE-based generation projects only marginally. For example, the IIM study concludes, citing experience with wind power auctions, that there is no doubt that the auctions lead to significant reduction in prices, but it is questionable whether the e-reverse auctions lead to further substantial gains in the form of reduction in prices at the second stage of the auction. While the tariff drop in tranche 1 and tranche 2 was dramatic, in subsequent tranches it stabilised. This is similar to what has been observed in solar auctions too. (IIM pp36)

Understandably, the participants of the Indian wind and solar power auctions, and especially the wind manufacturers, have questioned the utility of the second-stage eRA. They have contended that ultra-low tariffs are not sustainable and would cause long-term damage to the manufacturing base of these RE segments in the country (pp 6 IIM). Given these findings, it may well be asked whether it is worthwhile extending the overall auction process to the e-reverse stage, as in the auctions staged by the SECI. Further, it is debatable whether the two stages of the SECI’s auction lead to an even more efficient outcome when seen against the wider context of a larger, national economy? Nash equilibrium, which is a centrepiece of game theory5 and, by 76  Renewable Energy in India

extension, of auction theory, provides essential guidance on this. A major issue with Bayes–Nash equilibrium criterion is that it is compatible with multiple equilibria, each of them yielding several optimal auctions, with a differentiated benefit structure between buyers and sellers. That apart, as Bulow and Roberts (1989) have shown, the sealed-bid first-price auction with an upward advancing price leads to a third-degree price discrimination in a market characterized by a monopolistic seller. This certainly is not the desired outcome, when viewed from the perspective of a larger economy. Similarly, if one considers its corollary to the eRA, that too yields a similar result; but with a difference that the SECI, which practically functions as a negotiator on behalf of numerous electricity consumers, functions like a monopsonistic buyer on behalf of them at the e-bid auction stage of its auction process. While this optimizes the SECI’s benefit on behalf of consumers, at the expense of project developers, its auction process needs to be reviewed against the requirements of an efficiently functioning national economy, especially when the government strives to achieve greater efficiency across the different sectors of the economy. So what could be the alternative? Here, the Chinese experience sheds useful insights.

Chinese Approach After using the FIT approach to pricing electricity for promoting commercialization of RE power generation for several years,6 China shifted to auctions in 2003. It realized that the competitive bidding approach as a price discovery mechanism to support the setting up of a nationwide tariff for solar and wind power farms made greater economic sense than persisting with the FITs, which it had done until then. However, alarmed by the rashness of the inexperienced bidders, it entirely reworked its price criterion to benefit the bids Renewable Energy Pricing in India  77

closest to the average price (estimated by excluding the highest and lowest bid prices) found by averaging the price bids in the auction. Since then, it has been using auctions intermittently to keep tabs on prices in the rapidly evolving global RE market and to reset FIT prices from time to time. Thus, China has found auctions more effective in revealing costs and establishing cost benchmarks for the setting up of more appropriate and economically efficient FITs. The use of auctions for price discovery in China has significantly reduced the likelihood of FITs being above market equilibrium prices, thus avoiding the excessive addition of RE capacity and a heavy surcharge on consumers that excess capacity has entailed elsewhere.7 One important lesson that is particularly relevant from China’s experience for India is that winning bid prices that are lower than actual costs end up deterring the development of RE sources. The FIT levels established by the Chinese government from time to time have been comparable to the average Chinese auctioned prices and slightly slanted towards the upper end of the price bids. This pricing strategy has been found to be more conducive to rapid capacity expansions, as it has encouraged a greater number of potential investors to become interested in these projects. This finding is particularly important considering that the Indian government has set ambitious targets for creating gridconnected wind and solar capacities in the country.

Chapter Conclusion This chapter presented a comprehensive case study on the formation of the benchmark for capital costs for renewable technologies at the CERC and a comparative analysis of the cost-plus and auction routes of tariff discovery for renewable. For reasons explained in the previous chapter, while, from the point of view of economic theorists, methods such as LRMCs may be the most appropriate theoretically for forming tariffs, they are not practicable.

78  Renewable Energy in India

Instead, the average costs, though not quite appropriate from the point of view of promoting overall economic efficiency, have been found to be the most practicable. Under these circumstances, the CERC’s emphasis had been on consistency in developing tariffs for RE technology-based power plants rather than attending to purists’ concern. This had merit in itself, considering that the stakeholders look for consistency and transparency in the treatment of the various elements of costs, particularly the capital costs, in arriving at power tariffs. While preferential tariffs based on full cost approach and return on equity may have provided the initial basis for the promotion of power projects based on RE, the stipulation in the EA, 2003, that the tariff design should integrate ‘all factors that encourage and promote competition, efficiency and better use of resources, good performance and optimal investments’ (Section 61 [c])], needs consideration. Indeed, the FIT has since been superseded by more robust market mechanism-based approaches yielding results close to those sought by market theorists.

Notes 1. http://cercind.gov.in/2020/draft_reg/DEM-RE-Tariff-Regulations2020. pdf (accessed on 9 February 2021). 2. A private model is that in which each bidder knows how much he/ she values an item under auction, but this value is private information to him/her. • In the common value model, the actual value is common to all, but the bidders in auction have different private information about what the actual value is. In this situation, each bidder is inclined to revise the estimate of his/her value after knowing any of the other bidders’ signals. • Finally, a general model encompasses both of the above cases as special cases but allows each bidder’s value to be a general function of all signals. 3. Michael R. Mullen, Tamara Dinev, John L. Hopkins and Dennis F. Kehoe, ‘Evidence of Revenue Equivalence in B2B Open, Reverse e-Auctions and First Price Sealed Bids’ (2008). Available at http:// www.jgbm.org/page/48%20MichaelMullen.pdf (accessed on 9 February 2021).

Renewable Energy Pricing in India  79

4. Antoine Mandel and Herbert Gintis, ‘Decentralized Pricing and the Equivalence between Nash and Walrasian Equilibrium’ (2016). Available at https://ideas.repec.org/a/eee/mateco/ v63y2016icp84-92.html (accessed on 9 February 2021). 5. Charles A. Holt and Alvin E. Roth, ‘The Nash Equilibrium: A Perspective’, ed., Vernon L. Smith (2004). Available at https://www. pnas.org/content/101/12/3999 (accessed on 9 February 2021). 6. Gabriela Elizondo Azuela, Luiz Barroso, Ashish Khanna, Xiaodong Wang, Yun Wu and Gabriel Cunha, ‘Performance of Renewable Energy Auctions, Experience in Brazil, China and India’ (Policy Research Paper No. 7062, 2014). Available at https://openknowledge. worldbank.org/handle/10986/20498 (accessed on 9 February 2021). 7. Gabriela Elizondo Azuela and Luiz Augusto Barroso, ‘Design and Performance of Policy Instruments to Promote the Development of Renewable Energy: Emerging Experience in Selected Developing Countries’ (Working Paper No. 22; Washington, DC: World Bank, 2011).

References Auction Theory: A Guide to Literature, The Economic Theory of Auction, P Klemperer (ed), Edward Elgar (Pub), Cheltanham, UK, Yr2000. Ausubel L, P Cramton and P Milgrom, The Clock Proxy Auction; A Practical Combinatorial Auction Deisign, in Peter Cramton, Yoav Shoham and Richard Steingerg (ed), Combinatorial Auction, MIT Press 2006 Bulow J J and Roberts D J (1989), The Simple Economics of Optimal Auctions, Journal of Political Economy, 1060–90. Indian Institute of Management (IIM), Lucknow, Analysing Tariff Based e-Reverse Auction versus Closed Bidding in Wind and Solar Sectors, Report Submitted to the Ministry of New and Renewable Energy. Klemperer, P D (1998), Auctions with Almost Common Value, European Economic Review, 42. Klemperer, P D (1998), Auctions with Almost Common Value, European Economic Review. Myerson R B (1981), Optimal Auction Design, Mathematics of Operation Research, 6, 58–73. Peter Cramton (2009), Spectrum Auction Design, University of Maryland, Dept of Economics, August 15, 2009, 30 pages. Peter Cramton (2009), Spectrum Auction Design, University of Maryland, Dept of Economics, August 15, 2009, 30 pages. Riley J G and Samuelson W F (1981), Optimal Auction, American Economic Review, 71, 381–92.

80  Renewable Energy in India

Andhra Pradesh

Assam

Bihar

Chandigarh

2

3

4

5

S. No. States/UTs

1. Levelized tariff with AD 4.82 2. Levelized tariff without AD 5.22

 

 

2019– 2020

Year (FY)

2 Sep 2019

 

 

2019– 2020

 

 

30 Mar 2017– 2017 2018

2 Sep 2019

1. Levelized tariff with AD 6.51 2. Levelized tariff without AD 7.04

1. Levelized tariff with AD 4.35 2. Levelized tariff without AD 4.76

Order Date

Generic Tariff (`/kWh)

Wind Tariffs

 

2019– 2020 (for gross metering)

2 Sep 2019

1 Apr 2019

2019– 2020 (for gross metering)

2019– 2020

16 Nov 2016– 2016 2017

 

2 Sep 2019

Year (FY)

(Appendix 5A Continued)

1. Levelized tariff with AD 4.88 2. Levelized tariff without AD 5.27

4.17

 

 

1. Levelized tariff with AD 6.63 2. Levelized tariff without AD 7.16

Order Date

Solar PV Tariffs Generic Tariff (`/kWh)

Appendix 5A  State-wise Latest Wind and Solar Tariff Rates

 

Chhattisgarh

Dadra & Nagar 1. Levelized tariff with Haveli AD 4.82 2. Levelized tariff without AD 5.22

Daman & Diu

Goa

6

7

8

9

1. Levelized tariff with AD 4.82 2. Levelized tariff without AD 5.22

Diu 1. Levelized tariff with AD 3.34 2. Levelized tariff without AD 3.62 Daman 1. Levelized tariff with AD 4.57 2. Levelized tariff without AD 4.95

Generic Tariff (`/kWh)

2 Sep 2019

2 Sep 2019

2 Sep 2019

 

Order Date

Wind Tariffs

S. No. States/UTs

(Appendix 5A Continued)

2019– 2020

2019– 2020

2019– 2020

 

Year (FY)

1. Levelized tariff with AD 4.61 2. Levelized tariff without AD 4.98

1. Levelized tariff with AD 4.61 2. Levelized tariff without AD 4.98

1. Levelized tariff with AD 4.61 2. Levelized tariff without AD 4.98

1. 0.5 MW–2 MW 4.53, 2. 2 MW–5 MW 4.11

Generic Tariff (`/kWh)

Year (FY)

2 Sep 2019

2 Sep 2019

2 Sep 2019

2019– 2020 (for gross metering)

2019– 2020 (for gross metering)

2019– 2020 (for gross metering)

16 Mar 2020– 2020 2021

Order Date

Solar PV Tariffs

Himachal Pradesh

Jharkhand

Karnataka

10

11

12

3.26

 

 

6 May 2020

 

 

2020– 2021

 

 

1 Aug 2019

27 Dec 2017

8 Jul 2019

2019– 2020

2017– 2018

2019– 2020

(Appendix 5A Continued)

1. Solar PV (MW) 3.08; 2. Solar PV (kW) 3.07 (without subsidy); 2.32 (with subsidy); 3. Solar PV (1 kW to 10 kW) 3.99 (without subsidy); 2.97(with subsidy);

 

Projects to be set up in other than industrial areas and urban areas up to 1.00 MW 3.98 Above 1.00 MW up to 5.00 MW–3.94 Projects to be set up in industrial areas and urban areas up to 1.00 MW 4.06 Above 1.00 MW up to 5.00 MW 4.02

Lakshadweep

Madhya Pradesh

Odisha

Puducherry

14

15

16

17

1. Levelized tariff with AD 4.48 2. Levelized tariff without AD 4.14

6.24

4.78

1. Levelized tariff with AD 6.56 2. Levelized tariff without AD 7.10

Wind Zone 1 6.60, Wind Zone 2 6.00, Wind Zone 3 5.28, Wind Zone 4 4.40, Wind Zone 5 4.13

Kerala

13

2019– 2020

2017– 2018

Year (FY)

2 Sep 2019

15 Jan 2014 2019– 2020

2016– 2017

43,531 2019– 2020

2 Sep 2019

2 Nov 2017

Order Date

Wind Tariffs

Generic Tariff (`/kWh)

S. No. States/UTs

(Appendix 5A Continued)

1. Levelized tariff with AD 4.61 2. Levelized tariff without AD 4.98

11.44 (first 12 years) 6.78 (next 13 years)

5.45

1. Levelized tariff with AD 6.63 2. Levelized tariff without AD 7.16

5.68

2019– 2020 (for gross metering)

2017– 2018

Year (FY)

2 Sep 2019

15 Jan 2014

2019– 2020 (for gross metering)

2016– 2017

43,531 2019– 2020

2 Sep 2019

2 Nov 2017

Order Date

Solar PV Tariffs Generic Tariff (`/kWh)

Rajasthan

Tamil Nadu

Telangana

18

19

20

3.61

1. Levelized tariff with AD 2.80 2. Levelized tariff without AD 2.86

In case of Jodhpur Jaisalmer and Barmer: 1. Levelized tariff with AD 4.87, 2. Levelized tariff without AD 5.26, In case of others: 1. Levelized tariff with AD 5.12, 2. Levelized tariff without AD 5.52

6 Oct 2018

13 Apr 2018

10 Jul 2017

2019– 2020

2019– 2020 extended till until a new order is issued

2017– 2018

 

2019– 2020

 

 

29 Mar 2019– 2019 2020 extend till until a new order is issued

7 Jan 2020

(Appendix 5A Continued)

1. Levelized tariff with AD 2.80 2. Levelized tariff without AD 3.04

 

1. Levelized tariff with AD 5.88 2. Levelized tariff without AD 6.50

Tripura

Uttarakhand

21

22

Source: Websites of SERCs. Note: AD = Accelerated depreciation.

 

Generic Tariff (`/kWh)

Year (FY)

 

 

16 Oct 20152015 2016– 20192020

Order Date

Wind Tariffs

S. No. States/UTs

(Appendix 5A Continued)

Gross tariff 4.73 Net tariff 4.48

1. Levelized tariff with AD 6.27 2. Levelized tariff without AD 6.95

Generic Tariff (`/kWh)

Year (FY)

7 Jun 2019

2019– 2020

16 Oct 20152015 2016– 20192020

Order Date

Solar PV Tariffs

SECI Wind-I 1000 MW

GUVNL 500 MW

2

Auction

1

Sr. No

8

5

50

Adani Green Energy (MP) Limited

38

18.9

Oil India Limited

SJVN Limited

35.7

Renew Power Ventures Pvt Ltd

50

29.9

Betam Wind Energy Pvt Ltd

Powerica Limited

100

30

Verdant Renewable Pvt Ltd

K. P. Energy Ltd

197.5

250

Ostro Kutch Wind Private Limited

Sprng Energy Pvt Ltd

250

Inox Wind Infrastructure Services Limited

250 249.9

Green Infra Wind Energy Limited

Quantum (MW) Won

Mytrah Energy India Private Limited

Wind Developer Number Wind Developer Name

Appendix 5B  Bid Tariff (Wind)

2.43

2.43

2.45

2.44

2.44

2.44

2.43

2.43

3.46

3.46

3.46

3.46

3.46

Winning Tariff

(Appendix 5B Continued)

2017 November

2017 February

Tender Year- Month

SECI Wind-II 1000 MW

MSEDCL 500 MW

4

Auction

3

Sr. No

6

5

124.4

75.6

Hero Wind Energy Private Limited

Torrent Power Limited

100

Mytrah Energy

50

Inox Wind

50

Adani Green Energy (MP) Limited 75

250

Green Infra Wind Energy Limited 75

250

Inox Wind Infrastructure Services Limited

Adani Green Energy

200

Orange Sironj Wind Power Private Limited

KCT Renewable Energy Private Limited

250

Quantum (MW) Won

ReNew Power Ventures Private Limited

Wind Developer Number Wind Developer Name

(Appendix 5B Continued)

2018 March

2017 October

Tender Year- Month

2.87

2.86

2.86

2.86

2.85

2.85

2.65

2.65

2.65

2.64

2.64

Winning Tariff

SECI-III 2000 MW

SECI-IV 2000 MW

5

6

8

7

Inox Wind Infrastructure Services Limited

300 285 200 100 250 300 300

Sprng Energy Private Limited

BLP Energy Private Limited

Betam Wind Energy Private Limited

Inox Wind Infrastructure Services Limited

Adani Green Energy (MP) Limited

Mytrah Energy (India) Private Limited

Renew Wind Energy (TN) Private Limited

Betam Wind Energy Pvt Ltd 250

300 50.2

Alfanar Company

Srijan Energy Systems Private Limited

250

Adani Green Energy (MP) Limited

499.8

200

Green Infra Wind Energy Limited

Torrent Power Limited

400 300

ReNew Power Ventures Private Limited

2.44

2.52

2.52

2.51

2.51

2.51

2.51

2.51

2.51

2.45

2.45

2.45

2.44

2.44

2.44

(Appendix 5B Continued)

2018 April

2018 February

NTPC 2000 MW (allocated 1200 MW)

SECI-V 1200 MW

8

Auction

7

Sr. No

5

6

115 300 300 300 175

Torrent Power Limited

Adani Green Energy Limited

Alfanar Company

Sitac Kabini Renewables Limited

Ecoren Energy India Private Limited

50

300

Hero Wind Energy Private Limited

Fasten Power

300

50

Srijan Energy

ReNew Wind Energy

200 300

Mytrah Energy

Quantum (MW) Won

Sprng Vayu Vidyut Private Limited

Wind Developer Number Wind Developer Name

(Appendix 5B Continued)

2018 September

2018 August

Tender Year- Month

2.77

2.77

2.77

2.76

2.76

2.83

2.82

2.81

2.80

2.79

2.77

Winning Tariff

SECI-VI 1200 MW

GUVNL-II 1000 MW (allocated 745 MW)

9

10

8

6

150 50.6 125

Srijan Energy System Private Limited

Powerica Limited

Zenataris Renewable Energy Private Limited

200 113.6

Adani Renewable Energy Park (Gujarat) Ltd

40

100

Renew Wind Energy (Karnataka Two) Pvt Ltd

Inox Wind Energy

Viridi Clean Alternatives Pvt Ltd

100.8

100

Vena Energy Shivalik Wind Power Pvt Ltd

Sarjan Realities Ltd

50.6

40

Powerica Ltd

Anisha Power Projects Pvt Ltd

324.4

300

Ostro Energy Private Limited

SBESS Services Projectco Two Private Limited

250

Adani Renewable Energy Park (Gujarat) Limited

2.95

2.95

2.95

2.95

2.87

2.80

2.80

2.80

2.83

2.83

2.82

2.82

2.82

2.82

(Appendix 5B Continued)

2019 January

2019 February

SECI-VIII 1800 MW (allocated 440 MW)

12

2

4

250 190

Italian energy company Enel

130

China Light and Power (CLP)

100

Adani Renewable Energy Park (Gujarat) Limited

50

200

Quantum (MW) Won

Sprng Vaayu Urja Private Limited

Ostro Energy Private Limited

Betam Wind Energy Private limited

Wind Developer Number Wind Developer Name

2019 September

2019 February

Tender Year- Month

2.73

2.84

2.83

2.83

2.82

2.81

2.79

Winning Tariff

Source: Compiled by the authors from various public sources, e.g. Orders of State Electricity Regulatory Commissions, websites of MNRE, SECI etc.

SECI-VII 1200 MW (allocated 480 MW)

Auction

11

Sr. No

(Appendix 5B Continued)

NTPC 250 MW

RUMS 750 MW

NHPC 50 MW

SECI 250 MW

SECI 500 MW

2

3

4

5

Auction

1

Sr. No

2

3

1

3

1

250

Solenergi Power

200 300

SBG Cleantech One Limited

100

SBG Cleantech Three Limited

ACME Solar Holdings Private Limited

100

50

Avaada Power Private Limited

Phelan Energy Group Ltd

50

250

ACME Solar Holdings

Larsen & Toubro Ltd

250

250

Quantum (MW) Won

Mahindra Renewable Pvt Ltd

Solairedirect

Solar Developer Number Solar Developer Name

Appendix 5C  Bid Tariff (Solar)

May

May

June

February

April

2.45

2.44

2.63

2.62

2.62

5.7

2.97

2.97

2.98

3.15

Winning Tariff

(Appendix 5C Continued)

2017

2017

2017

2017

2017

Tender Year- Month

6

Sr. No

TANGEDCO 1500 MW

Auction

16

1 1

Dev International

10

GRT Silverwares (GRT)

Sunlight (Udayasooriyan)

10

GR Thanga Maligai & Sons (GRT)

5

10

Dynamize Solar

50

100

ReNew Solar

GR Thanga Maligai Firm (GRT)

100

NVR Energy (Atha Group)

Shapoorji Pallonji Infra

100

Rays Power Infra

50

100

Narbheram Vishram (Atha Group)

Talettutayi Solar Projects Two (Solar Arise)

100

Solitaire BTN Solar (HPPPL)

54

100

Raasi Green Energy

Sai Jyoti Infrastructure Ventures

709

Quantum (MW) Won

NLC India

Solar Developer Number Solar Developer Name

(Appendix 5C Continued)

2017

September

Tender Year- Month

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

3.47

Winning Tariff

SECI 250 MW

SECI 500 MW

GUVNL 500 MW

MAHAGENCO 300 MW (allocated 250 MW)

KREDL 860 MW (allocated 760 MW)

7

8

9

10

11

11

2

4

2

2

75

Gujarat Industries Power Company Ltd

185 106 85

ACME Solar

Asian Fab Tec

50

200

Shapoorji Pallonji

Shapoorji Pallonji

Azure Power

260

75

Gujarat State Electricity Corporation Ltd

Azure Power India Pvt Ltd

90

GRT Jewellers India Pvt Ltd

200

SBE Four Limited

50 300

ReNew Solar Power Private Limited

Hero Solar Energy Private Limited

200

Azure Power India Private Limited

February

May

September

December

December

3.24– 3.34

2.94– 3.15

2.94– 3.07

3.26

3.07

2.67

2.67

2.66

2.65

2.48

2.47

2.49

2.48

(Appendix 5C Continued)

2018

2018

2017

2017

2017

Sr. No

Auction 80 99 45 55 35 30 20 20

ReNew Power

Greenko

TEP Rooftop Solar

Ekialde Solar

Rays Power Infra

Max Planck Solar

Svarog Global

Quantum (MW) Won

Emmvee

Solar Developer Number Solar Developer Name

(Appendix 5C Continued) Tender Year- Month

3.54

3.12– 3.31

3.16– 3.20

3.15– 3.19

3.04– 3.07

3.30– 3.36

3.15– 3.28

3.52– 3.54

Winning Tariff

APDCL 100 MW (allocated 85 MW)

KREDL 550 MW

SECI 750 MW

SECI 200 MW

SECI -I 2000 MW

12

13

14

15

16

6

1

3

3

2

250

Ayana Renewable Power Private Limited

250 250 600

Hero Solar Energy Private Limited

Mahindra Susten Private Limited

Azure Power India Pvt Ltd

50

250

Shapoorji Pallonji Infrastructure Capital Company Private Limited

Mahoba Solar (UP) Private Limited

600

ACME Solar Holdings Limited

250

250

SBE Renewables Twenty Five Private Limited

250

100

Azure Power

Sprng Soura Kiran Vidyut Private Limited

150

Avaada Energy

SB Energy Seven Private Limited

300

10

Maheswari Mining and Energy Pvt Ltd

ReNew Power

75

Azure Power

July

May

July

March

June

2.54

2.53

2.53

2.53

2.52

2.44

2.82

2.71

2.70

2.70

2.93

2.92

2.91

3.19

3.37

(Appendix 5C Continued)

2018

2018

2018

2018

2018

SECI-II 3000 MW (allocated 600 MW)

NTPC 750 MW

NTPC 2000 MW (allocated 1400 MW)

KREDL 650 MW (allocated 500 MW)

18

19

20

Auction

17

Sr. No

2

4

3

1

250

Tata Power Renewable Energy Ltd (TPREL)

600

SB Energy

250

300

Azure Power

Fortum Corporation

500

Shapoorji Pallonji

250

SB Energy 600

250

Ayana Renewable Power

ACME Solar

250

600

Quantum (MW) Won

Sprng Energy

ACME Solar Holdings Limited

Solar Developer Number Solar Developer Name

(Appendix 5C Continued)

2018

2018

2018

2018

July

August

May

July

Tender Year- Month

2.85

2.85

2.60

2.59

2.59

2.59

2.73

2.73

2.72

2.44

Winning Tariff

MSEDCL 1000 MW (allocated 235 MW)

MSEDCL 1000 MW

21

22

6

4

20 200 250 250 150 130

Mahoba Solar (UP) Private Limited (Adani)

ReNew Power

ACME Solar

Tata Power Renewable Energy Limited

Azure Power

100

JLTM Energy India Private Limited

Juniper Green Energy Pvt Ltd (formerly AT Capital Advisory India Pvt Ltd)

5

50

TPSOL RESCO Three Pvt Ltd

Kintech Synergy Pvt Ltd

80

Shapoorji Pallonji Infrastructure Capital versus Shapoorji Pallonji Infrastructure Capital Company Pvt Ltd

May

November

2.72

2.72

2.72

2.72

2.71

2.71

3.15

3.15

3.13

3.09– 3.15

(Appendix 5C Continued)

2018

2018

GRIDCO 200 MW

OREDA (6 MW)

GUVNL 500 MW

KREDL 150 MW

24

25

26

Auction

23

Sr. No

1

3

1

5 20 50 30

Gupta Power

Eden Renewables

ACME Solar

100

Gaya Solar (Bihar) Pvt Ltd (SPV of Adani Green Energy Ltd)

150

300

Avaada Sunrise Energy Pvt Ltd (SPV of Giriraj Renewables Private Limited)

Giriraj Renewables

100

Aditya Birla Renewables Limited

6

25

Sukhbir Agro

Azure Power

75

Quantum (MW) Won

Aditya Birla Renewables

Solar Developer Number Solar Developer Name

(Appendix 5C Continued)

2018

2018

2018

2018

October

September

September

July

Tender Year- Month

2.92

2.44

2.44

2.44

3.13

3.2

3.19

3.19

3.19

2.79

Winning Tariff

KREDL 200 MW (allocated 100 MW)

UPNEDA 500 MW

UPNEDA 550 MW

27

28

29

9

9

1

20 20 50 50 50

Maheswari Mining and Energy PVT Ltd

Energy PVT Ltd

Sukhbir Agro Energy Ltd

Talettutayi Solar Projects Five Pvt Ltd

Eden Renewable

70

EDF (Bastille Solar)

100

70

EDF (Bastille Solar)

Avaada (Giriraj Renewables)

85

NTPC

100

50

Mahoba Solar

Giriraj Renewables Pvt Ltd

20

140

100

Maheswari Mining and Energy Pvt Ltd

NTPC

Asian Fab Tec

December

November

October

3.07

3.07

3.04

3.02

3.23

3.21

3.21

3.20

3.19

3.19

3.19

3.17

3.17

2.89

(Appendix 5C Continued)

2018

2018

2018

KREDL 100 MW

SECI 129 MW

MSEDCL 1000 MW

31

32

Auction

30

Sr. No

25

Adani (Mahoba Solar)

4

1

300 300 350

Renew Power

Avaada Energy

50

129

ACME Solar

Shiv Solar Private Limited

Bharat Heavy Electricals Limited

20

50

Tata Power Renewable Energy Limited (TPREL) 80

50

Tata Power Renewable Energy Limited (TPREL)

Shapoorji Pallonji Infrastructure Capital Company (SP Infra)

50

Adani (Mahoba Solar)

Think Energy Partners (TEPSOL)

50

Jakson Power

2

Quantum (MW) Won

Solar Developer Number Solar Developer Name

(Appendix 5C Continued)

2019

2019

2019

May

January

January

Tender Year- Month

2.75

2.75

2.74

2.74

4.38

2.91

2.91

3.08

3.08

3.07

3.07

3.07

Winning Tariff

GUVNL 500 MW

SECI-III 1200 MW

SECI-750 MW

33

34

35

5

4

5

300

SBSR Power Cleantech Eleven Private Limited

250 100 110

Sitara Solar Energy (UPC Renewables)

ReNew Power

40

ACME Solar

Palimarwar Solar House (LNB GROUP)

250

300

Eden Renewable Site Private Limited

Fortum Solar

300

Azure Power India Pvt Ltd

105

Renew Solar Power Private Limited 300

150

Adani Renewable Energy Park (Gujarat) Limited

ReNew Solar Power Private Ltd

120

75

Gujarat State Energy Corporation Limited

Juniper Green Energy Private Limited

50

Paryapt Solar Energy Private Limited

March

February

February

2.49

2.49

2.49

2.49

2.48

2.61

2.6

2.58

2.55

2.68

2.67

2.67

2.67

2.55

(Appendix 5C Continued)

2019

2019

2019

GUVNL-III 700 MW (allocated 500 MW)

SECI-250 MW

GUVNL 1000 MW (allocated 250 MW)

SECI-IV 1200 MW

37

38

39

Auction

36

Sr. No

4

1

3

4

300 300 300 250

Ayana Renewable Power Private Limited

ReNew Solar Power Private Ltd

Azure Power Maple Pvt Ltd

Mahindra Susten Private Limited

250

100

NTPC

Tata Power Renewable Energy Limited

100

Tata Power

50

2019

2019

2019

June

May

May

100

Tata Power Renewable Energy Limited

Talettutayi Solar (Solar Arise)

2.68

100

Gujarat Industries Power Company Limited

2.54

2.54

2.54

2.54

2.75

2.91

2.88

2.87

2.7

2.68

2.65

100

May

Winning Tariff

200

2019

Tender Year- Month

Gujarat State Energy Corporation Limited

Quantum (MW) Won

Electro Solar Private Limited

Solar Developer Number Solar Developer Name

(Appendix 5C Continued)

UPNEDA 500 MW (allocated 40 MW)

GUVNL 200 MW (allocated 100 MW)

GUVNL 750 MW (allocated 50 MW)

SECI-V 1200 MW (allocated 480 MW)

41

42

43

44

2

1

1

1

4 250

Hero Future Energies

330 150

GRT Jewellers India

50

100

40

SB Energy

Tata Power Renewable Energy Limited

Gujarat State Energy Corporation Limited

NTPC

70

200

Mahindra Susten

Azure Power

160

NTPC

2019

2019

2019

2019

2019

August

August

August

June

June

2.63

2.53

2.65

2.75

2.65

3.02

2.50

2.50

2.50

2.50

Source: Compiled by the authors from various public sources, e.g. Orders of State Electricity Regulatory Commissions, websites of MNRE, SECI etc.

SECI-II 750 MW (allocated 680 MW)

40

6

Renewable Purchase Obligation Does It Need a Revisit as Instrument for Market Creation?

Introduction Apart from the tariff intervention discussed in the previous chapter, RPO is yet another important instrument for the creation of market for renewable. This chapter discusses the concept of RPS practised especially in Europe as a market mechanism and compares it against the concept of RPO as understood in India and delves into the constraints that need be overcome to ensure its effectiveness as a facilitator for competition and a market for renewable.

Market Mechanism One way to achieve marginal cost pricing is by relying on markets to create competitive conditions in the renewable power

market. If there is sufficient number of suppliers competing in each of the renewable categories, markets would ensure that electricity from each of these sources is priced at the marginal cost of generation, irrespective of the pricing formula adopted by the individual suppliers. One of the issues, however, is what should be the nature of market-based instruments that would enable these technologies to flourish and grow in an environment where they cannot commercially compete with conventional power generation technologies without regulatory support. Besides, the other equally relevant task at the moment is to evolve a regulatory mechanism that would bring in competition within these segments and, hence, greater efficiency with it. Internationally, countries have promoted the commercialization of RE resources and their corresponding technologies in several ways, but FIT and RPO have been the two most popular approaches in recent times. The former is equivalent to the preferential tariff approach in India, in which the authorities notify sufficiently attractive tariffs for generation from these technologies, in a hope that this would bring forth investments in generation capacity based on these technologies. The latter, on the other hand, is in many ways different from the RPO mechanism that has been implemented so far in India.

Renewable Purchase Obligation In RPS, which has gained currency across various countries of Europe, Australia and some states in the USA, the regulatory authorities have, rather than specifying tariffs for different RE technologies, decreed a percentage of the total electricity consumption that electricity consumers must consume from RE generation. Practically, however, the obligation has operated at the level of electricity suppliers—distribution entities in the Indian context—who have then passed on the costs arising from this obligation to electricity consumers in the form of a separate surcharge in electricity bills.

Renewable Purchase Obligation  107

In this method, the environmental and commodity features of RE are untied into two distinct products. On the one hand, the electricity generated by RE units, just as generation from any conventional unit, is sold in the wholesale electricity market; the REC, which embodies the environmental feature, on the other hand, is sold as a green product on the PX. Its buyers are obligated entities (entities that must meet their RPO obligations) as well as voluntary buyers.

The UK Case To illustrate, in the UK, the new Renewables Obligation (RO) and associated Renewables Obligation (Scotland) amendment came into force in April 2002 as part of the Utilities Act, 2000. Under this, power suppliers have had to acquire from renewables a specified proportion of electricity they supply to their customers. It started with 3 per cent in 2003, rising gradually to 10.4 per cent in 2010 and to 15.4 per cent by 2015. Under this, the costs to consumers have been capped and the Obligation has been guaranteed in law until 2037.1 Eligible renewable generators receive the Renewables Obligation Certificates (ROCs) for each MWh of electricity generated. These certificates are then bought by electricity suppliers (distributors in Indian terminology) to fulfil their obligations. However, suppliers have an option to either meet their obligations by purchasing the required number of certificates or pay a ‘buyout’ price for the short fall. The buyout price, in fact, is essentially a penalty for non-compliance. Generally, the penalty is set as a maximum price of ROC or renewable electricity purchased under the obligation in the year. In Sweden, it is different. Consumers who do not comply pay a penalty which is 150 per cent (starting in 2005) of the average certificate price in the previous accounting period. The penalty in this case thus sets a moving ceiling price. Generally, the buyout price is fixed as the ‘price per MWh‘ shortfall.2 In the UK, however, this is adjusted every

108  Renewable Energy in India

year in line with the RPI. But it is not necessarily so in other countries that follow RPS. All the proceeds from buyout payments in the UK are recycled to suppliers in proportion to the number of ROCs they present. For example, if a supplier submits X per cent of the total number of ROCs issued in a year, he/she receives that percentage from the total amount paid by the defaulting companies in the buyout fund. Assuming that all costs and savings are passed on to consumers from this fund, the cost of ROCs is effectively paid by electricity consumers of supply companies that fail to present sufficient ROCs, while supply companies that submit ROCs in large numbers to that extent reduce the costs to their consumers. However, the manner in which the funds raised from the penalty are used is not the same across countries. Some transfer these to the RE fund, whereas others treat it as revenue to the government and transfer it to the general account of the government. The RO in the UK was designed as a market mechanism to increase the uptake of renewables, as the ROCs were to provide additional value over and above the price of electricity itself. As it turned out, it proved far more successful vis-a-vis the previous support mechanism, known in England and Wales as the NFFO, and delivered considerably more renewables. In the latter, the government had launched several rounds of competitive bidding contracts for RE in 1990, which came to be labelled as NFFO. In general, a distinct feature of the ROC mechanism has been that, unlike the FIT, which is notified by the regulatory authorities periodically, the price of the certificates is determined by the supply and demand for ROCs in the market. As for the renewable electricity, like electricity produced from conventional power plants, it trades as a commodity and its price is pegged to the wholesale price of electricity. Since the price of ROCs is determined in the market, it must be the case that the cost of ROC should correspond to the cost of the marginal renewable power producer. Renewable Purchase Obligation  109

Further, contrasting the two, while the FIT mechanism eliminates price uncertainty to RE generators/developers, there is no guarantee that it will produce a cumulative response that will achieve the national target for RE generation. In contrast, in a well-enforced RPO, since it is mandatory to meet the percentage obligation, there is a fair chance that the national target will be achieved. However, at what price this will be achieved remains uncertain. This could have consequences that may not always be palatable to consumers. Yet another of its drawback is that it could make financial closure difficult for developers in the absence of price clarity. Thus, the national goal of achieving a given proportion of RE consumption and the goal of achieving it in the utmost economically efficient way may not be fulfilled. In comparison, the obligation implemented so far in India, as we saw in the previous chapter, has been a variant of what has been the case internationally. On the demand side, while SERCs have mandated the RE percentage obligation for electricity DISCOMs in their respective areas, state regulators have departed from the usual approach by bringing in FITs to support different RE technologies. In effect, the system as it has operated in India so far is a hybrid of FITs and RPS mechanism. The regulators have, by specifying the RE targets as well as the FITs, tried to lower the overall uncertainty, in the hope that this would make investments attractive to the developers of these technologies, while limiting the impact of their higher costs to consumers. From what is experienced of the RPO in India, it is evident that the environmental feature of RE generation has remained tied with its electricity component. This has meant that the entities which have had a purchase obligation had to meet their requirements by the actual purchase of electricity from renewable power generators in the absence of trade-based instruments such as the RECs (RECs are equivalent to ROCs as mentioned above and have been introduced only in 2010 in India).

110  Renewable Energy in India

While this in itself may not be an issue as far as meeting the state targets for RE is concerned, one may as well ask whether the system as it stands is suitable for meeting the national RE goals set out in the National Action Plan for Climate Change (NAPCC), especially since the fragmented nature of its execution bears little correspondence with the requirements of the National Action Plan. Clearly, a far more universal approach is necessary for promoting RE in a country as vast and diverse as India if it is to exploit the potential of these technologies fully and efficiently.

National Action Plan for Climate Change Let us consider the NAPCC, which provides the basis for change in the system of promoting RE technologies in this country. Section 4.2.2 of the NAPCC requires that a ‘dynamic minimum renewable purchase standard (DMRPS) be set at a national level, with escalation each year till a pre-defined level is reached, at which time the requirements be revisited’. It further proposes that starting 2009–10, the national renewables’ standard (excluding hydropower with storage capacity in excess of daily peaking capacity, or based on agriculture based renewable sources that are used for human food) be set at 5% of the total grid purchase and increased by 1% each year for the next 10 years.

From this and a fact that the FOR has incorporated the NAPCC goals in its recommendations, one must presume that the FOR too has set this as a minimum obligation norm for each of the SERCs in the country, especially since what is in the plan is also expected to form part of India’s voluntary obligation undertaken at the Copenhagen Climate Summit (and reconfirmed at successive summits after that) to reduce the carbon intensity of the economy by 20 per cent by 2020. Given this context, it is apparent that the states are expected to set RPO targets, which achieve in aggregate the requirements

Renewable Purchase Obligation  111

of the national renewables objectives. In fact, in sync with this, the Working Group on Policies on Renewables of the FOR has recommended that the state commissions must specify a minimum RPO of 5 per cent by 2010 to conform to the NAPCC.

India’s Recent Targets for Renewable Capacity Addition In 2015, India announced its Intended Nationally Determined Contributions (INDC)3 commitment to have 40 per cent of the cumulative installed capacity from non-fossil fuel by 2030. For this, the country has set an ambitious target of adding 175 GW of generation capacity based on RE sources by 2022. This overall target includes 100 GW from solar, 60 GW from wind, 10 GW from biopower and 5 GW from small hydropower. The Ministry of Urban Development had requested all states and UTs in 2014 to issue the necessary directives to all state government departments for using rooftop of buildings under their control for solar power generation on a mandatory basis, as well as to local bodies under their jurisdiction to incorporate similar provision into their building by-laws so that installation of RTS on rooftops of all types of buildings in their jurisdiction may become mandatory. Further, the Ministry of Urban Development also issued Model Building Bye-Laws, 2016, in which suitable provisions for the installation of RTS on buildings have been incorporated. In addition to the above, the GOI set a more ambitious target of 44 per cent of the total electricity capacity from renewable sources by 2027 in the CEA’s4 National Electricity Plan.5 According to the Plan, India aims to have, by 2027, 275 GW from RE, 63.3 GW of hydroelectricity, 16.8 GW of nuclear energy and 25.7 GW from gas. The Tariff Policy (Tariff Policy, 2016) 6 notified by the Ministry of Power, GOI, provided that the long-term growth trajectory of RPOs would be prescribed by the Ministry of Power in consultation with the MNRE. In pursuance to the

112  Renewable Energy in India

policy framework and further to enable the achievement of the target of 175 GW of renewable capacity by March 2022, the Ministry of Power, in July 2016, notified the long-term trajectory of RPOs for solar as well as non-solar sources, uniformly for all states/UTs, initially for three years from 2016–2017 to 2018–2019. Subsequently, in June 2018,7 the RPO targets for a further three-year period from 2019–2020 to 2021–2022 were also notified (refer to Table 6.1). The MNRE also brought out state-wise RPOs for solar and nonsolar through their national portal for RPO (refer to Table 6.2).8 The National Solar Mission in 2011 further provided that within the percentage so made applicable, to start with, the SERCs shall also reserve a minimum percentage for purchase of solar energy which will go up to 0.25 per cent by the end of 2012–2013 and further up to 3 per cent by 2022. The question is whether there is consonance between the centre and the states on the RPO target setting and compliance. In this context, the Report of the Comptroller and Auditor General of India on the RE sector in India (Report No. 34 of 2015—Performance Audit)9 assumes importance as the report shows the status of compliance of the RPO targets by the utilities against the RPO targets set by the concerned SERCs. Details are provided in Appendices 6A.1, 6A.2 and 6B. It is evident from the data that there is a hiatus in the vision between the centre and the states in terms of the RPO setting. For example, RPO target (NAPCC target) ranged from 7 percent to 15 percent through 2011–12 to 2019–20 but Andhra Pradesh had set the target at a constant rate of 5 percent through 2011–12 to 2016–17 (refer to Appendix 6A.1). RPO Compliance remained all the more discouraging (refer to Appendix 6A.2). To achieve the national objectives with this system would require an effective coordination mechanism between states. This would be administratively unwieldy. So far, the SERCs have been setting RPO targets with regard mostly to RE availability in their areas. But to bring them in line with the national requirements requires a mechanism that is more conducive to achieving the national objective. Renewable Purchase Obligation  113

2.75

11.50

Solar (%)

Total (%)

14.25

4.75

9.50

2017–2018

17.00

6.75

10.25

2018–2019

17.50

7.25

10.25

2019–2020

19.00

8.75

10.25

2020–2021

21.00

10.50

10.50

2021–2022

MoP Order Dt. 14 June 2018

Source: Ministry of Power (https://powermin.nic.in/sites/default/files/webform/notices/RPO_trajectory_2019-22_ Order_dated_14_June_2018.pdf)

8.75

Non-solar (%)

2016–2017

MoP Order Dt. 22 July 2016

Long-term Growth Trajectory of Renewable Purchase Obligations for Solar and NonTable 6.1  solar as Determined by the Ministry of Power

Bihar

Chhattisgarh

4

5

Arunachal Pradesh Non-solar

2

Assam

Total

3

9.00

Solar

7.00 2.00 9.00

Solar

Total

7.75

Total

Non-solar

2.25

Solar

9.00

Total 5.50

4.00

Solar

Non-solar

5.00

14.3

Non-solar

Total

4.75

9.50

3

Non-solar

Andhra Pradesh

1

Solar

6

RE Technology

Sl. No State

11.00

3.50

7.50

9.25

3.25

6.00

11.00

5.00

6.00

17

6.75

10.25

11.00

4

7

13.00

5.00

8.00

11.50

4.75

6.75

13.00

6.00

7.00

0.00

13.00

5

8

17.00

8.00

9.00

17.00

8.00

9.00

0.00

17.00

7

10

(Table 6.2 Continued)

15.00

6.50

8.50

14.25

6.75

7.50

15.00

7.00

8.00

0.00

15.00

6

9

2017–2018 2018–2019 2019–2020 2020–2021 2021–2022 (%) (%) (%) (%) (%)

State-wise Renewable Purchase Obligations for Solar and Non-solar as per MNRE’s Table 6.2  National Portal for RPO

Himachal Pradesh

Jammu and Kashmir

9

10

7.25 1.25 8.50

Solar

Total

Total

Non-solar

4.75 14.25

Solar

10.00

Total 9.50

1.75

Solar

Non-solar

8.25

6.70

Non-solar

Total

Gujarat

8

2.50

JERC (Goa & UT)

7

Solar

14.25

Total 4.20

4.75

Solar

Non-solar

9.50

Non-solar

Delhi

6

9.50

1.50

8.00

17.00

6.75

10.25

12.70

4.25

8.45

9.00

3.60

5.40

17.00

6.75

10.25

10.50

1.75

8.75

18.00

7.25

10.25

14.30

5.50

8.80

11.50

4.70

6.80

19.75

8.75

11.00

11.50

2.00

9.50

19.00

8.75

10.25

15.65

6.75

8.90

14.10

6.10

8.00

12.50

3.00

9.50

21.00

10.50

10.50

17.00

8.00

9.00

17.00

8.00

9.00

2017–2018 2018–2019 2019–2020 2020–2021 2021–2022 (%) (%) (%) (%) (%)

RE Technology

Sl. No State

(Table 6.2 Continued)

Jharkhand

Karnataka

Kerala

Madhya Pradesh

Maharashtra

Manipur

11

12

13

14

15

16

3.75 7.75

Solar

Total

2.00 5.50 10.00

Solar

Total

12.50

Total

Non-solar

2.00

Solar

10.50

8.50

Total

Non-solar

1.50

Solar

7.50

Total 7.00

1.50

Solar

Non-solar

6.00

Non-solar

Total

Solar

Non-solar

4.00

Non-solar

12.70

8.00

2.50

13.75

2.75

11.00

9.25

1.75

7.50

9.75

2.75

7.00

10.00

5.50

4.50

14.30

9.00

3.00

15.00

3.50

11.50

12.00

4.00

8.00

6.00

0.25

5.75

11.55

6.55

5.00

17.00

10.50

3.00

17.00

8.00

9

6.60

0.25

6.35

(Table 6.2 Continued)

15.65

10.00

3.00

14.50

6.00

8.50

6.30

0.25

6.05

Non-solar

Mizoram

Meghalaya

Nagaland

Orissa

Punjab

17

18

19

20

21

0.43 2.50

Solar

Total

1.80 6.00

Solar

Total

7.50

Total 4.20

3.00

Solar

Non-solar

4.50

Non-solar

Total

Solar

Non-solar

2.07

6.50

2.20

4.30

9.50

4.50

5.00

4.00

0.75

3.25

9.50

4.00

5.50

11.00

5.50

5.50

5.00

1.00

4.00

11.50

5.00

6.50

6.00

1.25

4.75

14.50

6.50

8.00

2017–2018 2018–2019 2019–2020 2020–2021 2021–2022 (%) (%) (%) (%) (%)

Non-solar

Total

Solar

RE Technology

Sl. No State

(Table 6.2 Continued)

Rajasthan

Tamil Nadu

Tripura

Uttarakhand

Uttar Pradesh

22

23

24

25

26

4.75 14.25

Solar

Total

Total

Solar

Non-solar

9.50

13.00

Total

Non-solar

1.50

11.50

Solar

Non-solar

14.00

Total

14.25

Total 5.00

4.75

Solar 9.00

9.50

Non-solar

Solar

1.30

Biomass

Non-solar

8.20

Wind

17.00

6.75

10.25

14.00

1.75

12.25

17.00

6.75

10.25

1.50

8.75

18.00

7.00

11.00

15.00

2.00

13.00

17.50

7.25

10.25

1.50

8.75

20.50

8.00

12.50

21.00

10.50

10.50

1.60

8.90

(Table 6.2 Continued)

19.25

7.50

11.75

19.00

8.75

10.25

1.50

8.75

14.25

Total

Source: MNRE (https://rpo.gov.in/Home/About)

4.75

Sikkim

28

Solar

8.00

Total 9.50

0.60

Solar

Non-solar

7.40

Non-solar

West Bengal

27

17.00

6.75

10.25

2017–2018 2018–2019 2019–2020 2020–2021 2021–2022 (%) (%) (%) (%) (%)

RE Technology

Sl. No State

(Table 6.2 Continued)

Drawbacks of Current RPO Approach From what has been observed so far, it is evident that the RPO mechanism in India, in its prevailing form, has operated in too narrow a sphere to meaningfully contribute to the national requirements. The State Commissions’ insistence on the obligated entity to meet their purchase obligation by procuring RE generation from within their state boundaries hinders the achievement of the national objective. It limits the market reach and scope for RE generators and deprives electricity consumers of any benefit that the national-scale operation in green energy may offer. Besides, given that the RE costs are averaged in electricity tariffs charged to consumers and a fact that RE potential across India varies considerably, consumers in states with disproportionately higher RE obligations are put at a disadvantage vis-a-vis other states, as they are left to bear higher costs of RE generation through their electricity tariffs. In this context, the issue of RE integration cost in general and system balancing cost in particular also assumes importance. The balancing cost is estimated to be within the range of `1.11 per unit10—the balancing cost on account of provisioning of additional flexible high-cost gas-based generation, unscheduled interchange (UI) charge, standby charge and additional transmission charge. Seen from the point of view of the RE-deficit states, transmission infrastructure and associated costs are the major constraints. Encouraging interstate RE trade across India would require addressing infrastructural constraints. Notwithstanding open access, the prevailing constraints in transmission have been a major impediment to achieving interstate trade.11 This is despite the creation of a national grid. For the obligated entities to participate in interstate trade, the cost of procuring, after adjusting for transmission and wheeling charges, will have to be lower than what they may be paying at the moment to RE generators in their own states. Lastly, a number of states have already achieved high RPO

Renewable Purchase Obligation  121

levels and one suspects that they have little interest in adding more RE-based power in their system. Further, in the case of states that are deficient in RE resources, insistence on procurement of RE generation from within their boundaries results in a very low level of RPO targets in them. If they are to raise their targets, they must be provided with cost-effective options to meet them. The waiver of interstate transmission charges and losses provided in the policy of the GOI and regulations of the CERC (Tariff Policy, 2016,12 and Central Electricity Regulatory Commission [Sharing of Inter-State Transmission Charges and Losses] Regulations, 202013) is a step in this direction.

Chapter Conclusion For any trading mechanism to be successful, it would have to either overcome the constraints of the transmission infrastructure and associated costs, or sidestep them. While a detailed analysis of the various constraints, the steps taken so far to overcome them, the gaps that exist in the absence of a holistic view and the desirable action has been covered in the last chapter, the next chapter deliberates the initiatives taken in the form of the REC mechanism to address, inter alia, the constraints of interstate transferability of variable renewable, so as to facilitate better compliance of RPO. The FOR in India, responding to the challenge, developed a national framework for the implementation of RPO, based on trade of RECs. It called upon the CERC to frame a regulation to institutionalize it at the national level and to entrust SERCs to adopt this instrument for RPO compliance under Section 86 (1) (e) of the EA, 2003. This is discussed in the next chapter in detail.

Notes 1. https://www.ofgem.gov.uk/ofgem-publications/76340/ro-buy-outfund102010-pdf (accessed on 10 February 2021). 2. N. H. van der Linden, M. A. Uyterlinde, C. Vrolijk, Lars J. Nilsson, Kerstin Åstrand, Karin Ericsson, R Wiser and Jamil Khan, ‘Review

122  Renewable Energy in India

of International Experience with Renewable Energy Obligation Support Mechanisms’ (Petten: Energieonderzoek Centrum Nederland, 2005). 3. http://moef.gov.in/wp-content/uploads/2017/08/Press_ Statement__INDC_English.pdf (accessed on 1 October 2020) 4. https://en.wikipedia.org/wiki/Central_Electricity_Authority_ (India) (accessed on 10 February 2021). 5. https://www.cea.nic.in/reports/committee/nep/nep_jan_2018.pdf (accessed on 1 October 2020), 5.17. 6. https://powermin.nic.in/sites/default/files/webform/notices/ Tariff_Policy-Resolution_Dated_28012016.pdf (accessed on 1 October 2020). 7. https://powermin.nic.in/sites/default/files/webform/notices/RPO_ trajectory_2019–22_Order_dated_14_June_2018.pdf (accessed on 9 May 2020). 8. https://rpo.gov.in/Home/About (accessed on 9 May 2020). 9. https://cag.gov.in/sites/default/files/audit_report_files/Union_ Civil_Performance_Renewable_Energy_Report_34_2015.pdf (accessed on 9 May 2020), 205–206. 10. https://www.cea.nic.in/reports/others/planning/resd/resd_comm_ reports/report.pdf (accessed on 10 February 2021), 18. 11. Central Electricity Regulatory Commission, ‘Study on Determination of Forbearance and Floor Price’ (2010). Available at http://powerexindia.com/media/new/Images/Downloads/rec/ Final_Suo_Motu_Order_on_Determination_of_Forbearance_and_ Floor_Price_of_REC.pdf (accessed on 10 February 2021). 12. https://powermin.nic.in/sites/default/files/webform/notices/ Tariff_Policy-Resolution_Dated_28012016.pdf (accessed on 1 October 2020), para 6.4. 13. http://cercind.gov.in/2020/regulation/158-Reg.pdf (accessed on 1 October 2020), Regulation 13.

Renewable Purchase Obligation  123

Jammu & Kashmir

Karnataka

Kerala

Madhya Pradesh

Maharashtra

11

12

13

14

Himachal Pradesh

8

Jharkhand

Haryana

7

9

Gujarat

6

10

Bihar

Chhattisgarh

Assam

3

4

Arunachal Pradesh

2

5

Andhra Pradesh

1

NAPCC Target

S. No. State

6.00

3.30

2.00

10.00

1.50

5.00

5.00

1.50

6.00

7.00

2.50

3.60

7.25

3.00

3.00

10.01

1.50

6.00

5.25

3.00

2.80

5.00

7.00

8.00

4.00

3.90

7.25

4.00

5.00

10.25

2.05

7.00

5.75

4.00

4.20

4.20

5.00

8.00

9.00

5.50

4.20

7.25

4.00

5.00

10.25

3.10

7.00

5.75

4.50

5.60

5.60

5.00

9.00

9.00

7.00

4.50

4.00

6.00

10.25

8.00

5.75

5.00

7.00

7.00

5.00

10.00

9.00

4.80

4.00

7.50

11.25

9.00

1.00

5.00

11.00

5.10

9.00

12.25

10.00

1.25

5.00

12.00

5.40

13.50

1.50

13.00

5.70

14.75

1.75

14.00

6.00

16

2.00

15.00

2010­ 2011– 2012­ 2013– 2014– 2015– 2016– 2017– 2018– 2019– –2011 2012 –2013 2014 2015 2016 2017 2018 2019 2020

  Targets of Renewable Purchase Obligation Set by State Electricity Regulatory Appendix 6A.1 Commissions from 2010–2011 to 2019–2020 (in %)

UP

Uttarakhand

West Bengal

22

23

24

3.75

8.50

5.00

5.00

0.50

4.53

5.00

9.00

6.00

2.40

5.00

7.00

6.00

0.75

5.05

6.00

9.00

7.10

2.90

5.50

8.00

7.00

1.00

4.00

6.05

6.00

9.00

8.20

3.50

6.00

1.00

5.00

7.08

11.00

4.00

6.50

6.00

8.10

11.00

7.00

7.00

9.30

8.00

11.50

Source: Comptroller and Auditor General of India on Renewable Energy Sector in India (Report No. 34 of 2015 – Performance Audit).

Rajasthan

Tamil Nadu

Punjab

19

20

Odisha

18

21

Mizoram

Nagaland

16

17

Meghalaya

15

Kerala

Madhya Pradesh

Maharashtra

14

Karnataka

11

12

Jharkhand

10

13

Himachal Pradesh

Haryana

7

Jammu & Kashmir

Gujarat

6

8

Chhattisgarh

5

9

Assam

Bihar

3

Arunachal Pradesh

2

4

Andhra Pradesh

1

NAPCC target

S. No. State

6.00/5.77

3.00/3.38

0/10.70

2.00/0.19

10.00/12.00

1.50/1.06

5.00/2.76

5.00/0

1.50/1.00

0/8.40

6.00

2010–2011

7.00/ 7.15

2.50/NA

3.30/2.855

7.25/10.73

3.00/ 0.28

3.00/Nil

10.01/15.73

1.50/1.07

6.00/4.73

5.25/ 2.76

2.50/2.10

1.90/4.01

5.00/NA

7.00

2011–2012

RPO Notified/Achievement (in%)

8.00/ 7.05

4.00/ NA

3.60/2.47

7.25/9.93

4.00/0.39

5.00/Nil

10.25/17.26

2.05/0.97

7.00/ 6.50

5.75/2.96

4.00/ 2.90

4.20/3.44

4.20/8.41

5.00/1.75

8.00

2012–2013

9.00/ 7.66

5.50/ NA

3.90/ NA

7.25/10.97

4.00/0.42

5.00/Nil

10.25/16.69

3.10/0.94

7.00/672

6.25/ NA

4.50/1.89

5.60/ NA

5.60/8.87

5.00/NA

9.00

2013–2014

  Compliance of Renewable Purchase Obligation by the Utilities from 2010–2011 to Appendix 6A.2 2013–2014

UP

Uttarakhand

West Bengal

22

23

24

3.75/4.56

0/17.27

8.50/3.55

5.00/NIL

5.00/5.14

0.50/ 4.14

2.00/NA

4.53/NA

5.00/6.19

9.00/20.09

6.00/5.16

2.40/1.69

5.00/NA

5.00/NIL

6.00/ 7.76

0.75/ 3.41

3.00/1.47

5.05/3.78

6.00/4.68

9.00/26.13

7.10/6.30

2.90/2.59

5.500/ NA

5.00/NIL

7.00/14.45

1.00/ 5.00

4.00/2.54

6.05/3.15

6.00/4.45

9.00/20.04

8.20/7.25

3.50/3.08

6.00/ NA

5.00/NIL

9.00/11.99

1.00/ 3.80

Source: Comptroller and Auditor General of India on Renewable Energy Sector in India (Report No. 34 of 2015 – Performance Audit)

Rajasthan

Tamil Nadu

Punjab

19

20

Odisha

18

21

Mizoram

Nagaland

16

17

Meghalaya

15

Andaman & Nicobar

Andhra Pradesh

Arunachal Pradesh

Assam

1

2

3

4

S. No. States

States/DISCOMS

Assam Power Distribution Company Limited (APDCL)

1.00

2.75

0.25

Eastern Power Distribution Co. Ltd (EPDCL)

Department of Power, Arunachal Pradesh (DOP, AP)

0.25

1.65

4.00

4.75

3.00

3.00

2.50

5.00

6.75

4.00

4.00

3.60

6.00

 

5.00

5.00

4.70

7.00

 

6.00

6.00

6.10

1.00

 

 

 

 

1.16

 

 

 

 

 

 

 

 

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Solar Target (%)

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

Southern Power Distribution Co. Ltd (SPDCL)

Electricity Department, Andaman and Nicobar Administration (ED A&N)

DISCOM

Solar Achievement/ Compliance (%) Non-solar Target (%)

3.00

8.75

4.75

4.75

3.20

5.00

9.50

6.00

6.00

4.20

6.00

10.25

7.00

7.00

5.40

7.00

 

8.00

8.00

8.00

 

9.00

9.00

8.00

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

2.91

 

 

 

 

4.90

 

 

 

 

 

 

 

 

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Non-solar Achievement/ Compliance (%)

  State-wise RPO Target (FY 2016–2017 to FY 2020–2021) and RPO Compliance (FY 2016–2017 to Appendix 6B FY 2018–19)

Chhattisgarh Chhattisgarh State Power Distribution Company Ltd (CSPDCL)

Delhi

Dadra & Dadra & Nagar Nagar Haveli Haveli Power Distribution Corporation Ltd (DNHPDCL)

7

8

9

0.35

0.35

0.35

BSES Yamuna Power limited

Tata Power Delhi Distribution Ltd (TPDDL)

New Delhi Municipal Council (NDMC)

1.65

0.35

1.50

1.65

BSES Rajdhani Power limited

Chandigarh Electricity Department (CED)

Chandigarh

1.50

South Bihar Power Distribution Company Limited (SBPDCL)

6

1.50

North Bihar Power Distribution Company Limited (NBPDCL)

Bihar

5

2.50

2.75

2.75

2.75

2.75

2.00

2.50

2.25

2.25

3.60

4.75

4.75

4.75

4.75

3.50

3.60

3.25

3.25

4.70

6.75

6.75

6.75

6.75

5.00

4.70

4.75

4.75

6.10

7.25

7.25

7.25

7.25

6.50

6.10

6.75

6.75

1.41

 

 

 

0.41

 

1.40

1.50

1.50

0.08

 

 

 

 

 

1.06

2.25

2.25

 

 

 

 

 

 

 

2.80

2.79

3.20

8.65

8.65

8.65

8.65

6.50

3.20

5.00

5.00

4.20

8.75

8.75

8.75

8.75

7.00

4.20

5.50

5.50

5.40

9.50

9.50

9.50

9.50

7.50

5.40

6.00

6.00

8.50

8.00

7.50

7.50

6.80

3.54

 

 

 

8.04

 

1.23

5.00

5.00

0.00

 

 

 

 

 

1.21

5.50

5.50

 

 

 

 

 

 

 

6.93

5.30

(Appendix 6B Continued)

8.00

10.25 10.25

10.25 10.25

10.25 10.25

10.25 10.25

8.00

6.80

6.75

6.75

1.15

1.75

1.75

1.75

1.75

1.75

Electricity Department, Goa (EDG)

Dakshin Gujarat Vij Company Limited (DGVCL)

Madhya Gujarat Vij Company Limited (MGVCL)

Uttar Gujarat Vij Company Limited (UGVCL)

Paschim Gujarat Vij Company Limited (PGVCL)

Torrent Power LimitedDistribution Surat

11 Goa

12 Gujarat

1.75

1.75

1.75

1.75

3.00

2.50

2.50

4.25

4.25

4.25

4.25

4.25

3.60

3.60

5.50

5.50

5.50

5.50

5.50

4.70

4.70

6.75

6.75

6.75

6.75

6.75

6.10

6.10

2.46

1.88

1.88

1.88

1.88

1.54

0.71

2.59

1.83

1.83

1.83

1.83

2.38

0.80

3.67

2.77

2.77

2.77

2.77

3.56

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Solar Target (%)

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

1.65

DISCOM

Solar Achievement/ Compliance (%)

10 Daman & Diu Electricity Department of Daman & Diu (ED DD)

S. No. States

States/DISCOMS

(Appendix 6B Continued)

Non-solar Target (%)

8.25

8.25

8.25

8.25

8.25

2.80

3.20

8.35

8.35

8.35

8.35

8.35

4.20

4.20

8.45

8.45

8.45

8.45

8.45

5.40

5.40

8.80

8.80

8.80

8.80

8.80

6.80

6.80

8.90

8.90

8.90

8.90

8.90

8.00

8.00

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

5.79

6.73

6.73

6.73

6.73

1.06

1.86

8.24

7.60

7.60

7.60

7.60

4.09

3.63

7.95

9.27

9.27

9.27

9.27

5.30

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Non-solar Achievement/ Compliance (%)

1.80

1.80

1.80

1.80

1.80

Jharkhand Bijli Vitran Nigam Limited (JBVNL)

Damodar Valley Corporation (DVC)

Jamshedpur Utility Services Company Limited (JUSCO)

Tata Steel Limited (TSL)

Steel Authority of India Limited (SAIL)

15 Jharkhand

2.50

1.00

Dakshin Haryana Bijli Vitran Nigam Ltd (DHBVNL)

Himachal Pradesh State Electricity Board Ltd (HPSEBL)

1.00

Uttar Haryana Bijli Vitran Nigam Ltd (UHBVNL)

1.75

14 Himachal Pradesh

13 Haryana

Torrent Power LimitedDistribution Ahmedabad

3.75

3.75

3.75

3.75

3.75

4.75

2.50

2.50

1.75

5.50

5.50

5.50

5.50

5.50

6.75

4.00

4.00

4.25

6.55

6.55

6.55

6.55

6.55

7.25

5.50

5.50

5.50

6.55

6.55

6.55

6.55

6.55

8.75

7.00

7.00

6.75

 

 

 

 

 

2.50

 

 

2.46

 

 

 

 

 

 

 

 

2.59

 

 

 

 

 

 

 

 

3.67

3.50

3.50

3.50

3.50

3.50

9.50

2.75

2.75

8.25

4.00

4.00

4.00

4.00

4.00

9.50

2.75

2.75

8.35

3.00

3.00

8.80

3.00

3.00

8.90

4.50

4.50

4.50

4.50

4.50

5.00

5.00

5.00

5.00

5.00

 

 

 

 

 

9.50

 

 

5.79

 

 

 

 

 

 

 

 

8.24

 

 

 

 

 

 

 

 

7.95

(Appendix 6B Continued)

5.00

5.00

5.00

5.00

5.00

10.25 10.25 10.25

3.00

3.00

8.45

17 Kerala

16 Karnataka

S. No. States

States/DISCOMS

0.75

0.75

Hubli Electricity Supply Company Limited (HESCOM)

Mangalore Electricity Supply Company Limited (MESCOM)

0.50

0.75

Gulbarga Electricity Supply Company Limited (GESCOM)

Kerala State Electricity Board Ltd (KSEBL)

0.75

Chamundeshwari Electricity Supply Corporation Limited (CESC)

1.50

2.75

2.75

2.75

2.75

2.75

2.75

6.00

6.00

6.00

6.00

6.00

 

7.25

7.25

7.25

7.25

7.25

 

8.50

8.50

8.50

8.50

8.50

0.23

1.48

0.68

0.75

0.79

1.04

0.53

4.26

3.89

5.33

4.94

4.11

0.75

 

 

 

 

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Solar Target (%)

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

0.75

Solar Achievement/ Compliance (%)

Bangalore Electricity Supply Company Limited (BESCOM)

DISCOM

(Appendix 6B Continued)

Non-solar Target (%)

8.50

6.00

9.50

7.00

8.00

8.00

11.00 11.00

4.50

6.00

7.00

 

 

11.01 12.00 13.00 13.00 13.00

7.50

5.50

11.00 11.00 12.00 12.00 12.00

11.00 12.00 13.00 12.00 12.00

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

20.81

10.47

2.85

3.24

11.01 13.10

7.80

5.50

10.47 11.00

11.00 12.00

4.68

 

 

 

 

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Non-solar Achievement/ Compliance (%)

Meghalaya Power Distribution Corporation Limited (MePDCL)

22 Meghalaya

0.42

2.75

1.00

Brihanmumbai Electric Supply and Transport (BEST)

Manipur State Power Distribution Company Ltd (MSPDCL)

1.00

Maharashtra State Electricity Distribution Company Limited (MSEDCL)

21 Manipur

1.00

RInfra-D/Adani Electricity Mumbai Limited (AEML)

1.25

West DISCOM

1.00

1.25

East DISCOM

Tata Power Distribution (TPC-D)

1.25

Central DISCOM

19 Madhya Pradesh

20 Maharashtra

1.65

18 Lakshadweep Electricity Department, UT of Lakshadweep (LED)

0.43

4.75

2.00

2.00

2.00

2.00

1.50

1.50

1.50

2.50

0.75

6.75

2.75

2.75

2.75

2.75

1.75

1.75

1.75

3.60

1.00

 

3.50

3.50

3.50

3.50

 

 

 

4.70

1.25

 

4.50

4.50

4.50

4.50

 

 

 

6.10

 

0.00

1.01

0.38

0.74

1.10

 

 

 

 

 

 

0.69

0.79

0.73

1.55

 

 

 

 

 

 

 

 

0.79

3.23

 

 

 

 

7.00

7.00

7.00

4.20

7.50

7.50

7.50

5.40

 

 

 

6.80

 

 

 

8.00

1.58

8.75

2.07

9.50

3.25

10.25

4.00

 

 

 

 

 

 

 

 

 

2.14

 

0.92

9.03

 

 

11.38

10.00 10.57

7.45

 

 

 

 

2.29

10.00 10.50 10.97

 

 

 

 

(Appendix 6B Continued)

4.75

 

10.00 10.50 11.00 11.50 11.50

10.00 10.50 11.00 11.50 11.50

10.00 10.50 11.00 11.50 11.50

10.00 10.50 11.00 11.50 11.50

6.50

6.50

6.50

3.20

1.50

1.50

SOUTHCO

Western Electricity Supply Company of Orissa Limited (WESCO)

Puducherry Electricity Department (PED)

1.50

North Eastern Electricity Supply Company of Odisha Limited (NESCO)

26 Puducherry

1.50

Central Electricity Supply Utility (CESU)

25 Odisha

1.65

2.75

Department of Power, Nagaland (DPN)

24 Nagaland

2.75

2.50

3.00

3.00

3.00

3.00

4.75

4.75

3.60

4.50

4.50

4.50

4.50

6.75

6.75

4.70

5.50

5.50

5.50

5.50

7.25

 

6.10

 

 

 

 

8.75

 

0.02

 

 

 

 

0.00

0.00

 

 

 

 

 

0.00

 

 

 

 

 

 

0.00

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Solar Target (%)

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

Power and Electricity Department (P&ED), Mizoram

DISCOM

Solar Achievement/ Compliance (%)

23 Mizoram

S. No. States

States/DISCOMS

(Appendix 6B Continued)

Non-solar Target (%)

3.20

3.00

3.00

3.00

3.00

8.75

8.75

4.20

4.50

4.50

4.50

4.50

9.50

9.50

 

 

5.40

5.00

5.00

5.00

5.00

6.80

5.50

5.50

5.50

5.50

8.00

 

 

 

 

10.25 10.25 10.25

10.25

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

 

 

0.00

 

 

 

 

 

 

 

 

 

 

 

 

 

 

15.86 13.05 16.26

20.89

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Non-solar Achievement/ Compliance (%)

0.25

0.25

Northern Power Distribution Company of Telangana Limited (TSNPDCL)

Southern Power Distribution Company of Telangana Limited (TSSPDCL)

31 Telangana

2.50

Tamil Nadu Generation and Distribution Corporation Ltd (TANGEDCO)

30 Tamil Nadu

0.75

2.50

Jaipur Vidyut Vitran Nigam Limited (JVVNL)

Energy and Power Department, Sikkim (EPDS)

2.50

Jodhpur Vidyut Vitran Nigam Limited (JDVVNL)

29 Sikkim

2.50

Ajmer Vidyut Vitran Nigam Limited (AVVNL)

28 Rajasthan

1.30

Punjab State Power Corporation Limited (PSPCL)

27 Punjab

0.25

0.25

5.00

4.75

4.75

4.75

4.75

1.80

5.33

5.33

5.00

6.75

6.75

6.75

6.75

2.20

5.77

5.77

 

6.75

6.00

6.00

6.00

4.00

6.21

6.21

 

6.75

7.25

7.25

7.25

 

 

 

2.90

 

 

 

 

2.65

 

 

3.40

 

 

 

 

3.91

 

 

3.32

 

 

 

 

3.66

4.75

4.75

9.00

4.25

8.90

8.90

8.90

4.10

4.75

4.75

9.00

9.50

9.50

9.50

9.50

4.20

9.00

9.00

9.00

5.50

9.40

9.40

9.40

 

0.67

0.67

9.00

0.79

0.79

 

 

 

 

 

4.58

 

 

 

 

3.75

 

 

 

 

 

 

14.64 18.91 12.15

 

 

 

 

2.49

(Appendix 6B Continued)

0.73

0.73

 

10.25 10.25 10.25

10.25

10.25

10.25

4.30

1.00

1.00

1.00

1.00

1.00

1.00

Dakshinanchal Vidyut Vitran Nigam Ltd (DVVNL)

Kanpur Electricity Supply Company Ltd (KESCo)

Madhyanchal Vidyut Vitaran Nigam Ltd (MVVNL)

Pashchimanchal Vidyut Vitaran Nigam Limited (PVVNL)

Purvanchal Vidyut Vitaran Nigam Limited (PUVVNL)

Noida Power Company Limited (NPCL)

33 UP

 

1.00

1.00

1.00

1.00

1.00

1.00

 

1.00

1.00

1.00

1.00

1.00

1.00

 

2.00

2.00

2.00

2.00

2.00

2.00

 

3.00

3.00

3.00

3.00

3.00

3.00

 

0.69

0.43

0.43

0.43

0.43

0.43

 

0.83

0.01

0.01

0.01

0.01

0.01

 

 

1.07

1.07

1.07

1.07

1.07

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Solar Target (%)

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

Tripura State Electricity Corporation Ltd (TSECL)

DISCOM

Solar Achievement/ Compliance (%)

32 Tripura

S. No. States

States/DISCOMS

(Appendix 6B Continued)

Non-solar Target (%)

5.00

5.00

5.00

5.00

5.00

5.00

 

5.00

5.00

5.00

5.00

5.00

5.00

 

5.00

5.00

5.00

5.00

5.00

5.00

 

6.00

6.00

6.00

6.00

6.00

6.00

 

8.00

8.00

8.00

8.00

8.00

8.00

 

FY FY FY FY FY 2016– 2017– 2018– 2019– 2020– 2017 2018 2019 2020 2021

1.39

4.10

4.10

4.10

4.10

4.10

 

6.86

4.16

4.16

4.16

4.16

4.16

 

 

3.90

3.90

3.90

3.90

3.90

 

FY FY FY 2016– 2017– 2018– 2017 2018 2019

Non-solar Achievement/ Compliance (%)

0.25

0.25

0.25

0.25

0.25

35 West Bengal West Bengal State Electricity Distribution Company Ltd (WBSEDCL)

Calcutta Electric Supply Corporation (CESC)

Damodar Valley Corporation (DVC)

Durgapur Power Limited (DPL)

India Power Corporation Limited (IPCL)

0.30

0.30

0.30

0.30

0.30

4.75

0.40

0.40

0.40

0.40

0.40

6.75

 

 

 

 

 

7.25

 

 

 

 

 

8.75

 

 

 

 

 

0.30

 

 

 

 

 

2.64

Source: Compiled based on information available in websites of SERCs.

1.50

Uttarakhand Power Corporation Ltd (UPCL)

34 Uttarakhand

 

 

 

 

 

 

5.50

5.50

5.50

5.50

5.50

8.00

6.00

6.00

6.00

6.00

6.00

9.50

6.50

6.50

6.50

6.50

6.50

 

 

 

 

 

 

 

 

 

 

10.25 10.25 10.25

 

 

 

 

 

7.36

 

 

 

 

 

7.10

 

 

 

 

 

 

7

Renewable Energy Certificate (REC) Has It Outlived Its Life as Market-based Mechanism?

Introduction Continuing the discussion from the previous chapter regarding the constraint of the interstate transferability of variable renewable, coming in the way of RPO fulfilment by obligated entities, this chapter examines the framework of REC as a market-based instrument to address this constraint and, in turn, to facilitate RPO compliance. The CERC issued ‘Central Electricity Regulatory Commission (Terms and Conditions for Recognition and Issuance of Renewable Energy Certificate for Renewable Energy Generation) Regulations, 2010’ on 14 January 2010 framing the regulation as agreed in the FOR. What are its features? How does it compare with international mechanisms of a similar nature? Even more importantly, can it deliver what the government has sought to achieve? These are some of the questions that this chapter seeks to answer.

CERC’s Notification The CERC’s notification of 14 January 2010 (subsequently amended in 2010, 2013, 2014 and 2016) requires obligated entities to meet two distinct RPOs, namely solar and non-solar, through solar and non-solar RECs, respectively. Further, the notification provides for the issuance of solar certificates to generators of electricity from solar energy and non-solar certificates to generators of electricity from non-solar RE (for brevity, both are referred to in rest of the book as RECs). Entities having RE purchase obligation can acquire these certificates in fulfilment of their obligation only from the PX and not in any other manner. Bilateral transactions in certificates are thus ruled out. There is no restriction, however, on placing these certificates on any of the PX in the country, so long as they have obtained prior approval of their rules and by-laws, including the mechanism for price discovery for certificates, from CERC (Sec 8[2]).

Pricing of Certificates Logically, since the trade in certificates is meant to be conducted through PX, its price discovery must also happen there. The notification provides for this, but with a caveat that the CERC ‘may, in consultation with the Central Agency (designated by the Commission inter-alia for registration and issuance of RECs) and the Forum of Regulators provide for the forbearance and the floor price from time to time, separately for the solar and non-solar certificates’. How would these prices be determined? The notification spells this out requiring the following aspects to be taken into account in setting prices, namely variation in the cost of generation of different RE technologies falling under the solar and non-solar categories, across states in the country, variation in the pooled cost of purchase of electricity across states in the country, expected electricity generation from RE sources, including expected RE capacity Renewable Energy Certificate (REC)  139

under preferential tariff and expected RE capacity under the mechanism of certificates. The pooled cost in the regulation is defined as the weighted average pooled price at which the distribution licensee has purchased the electricity, including the cost of generation, if any, in the previous year from all energy suppliers, long-term and short term, but excluding those based on RE sources, as the case may be. After spelling out the basis for arriving at a forbearance and a floor price, the Commission awarded a study to a consultant firm to assess these prices and to make its recommendation. The Commission determined1 these prices in accordance with the following assumptions and principles for non-solar renewable technologies, namely the target for RE generation in the country for the year 2010–2011 taken as 6 per cent as per the NAPCC; it developed future scenarios for each of the RE technologies across states, by taking 2009 as a base year and the growth in capacities of each of the RE technologies in selected states, and making projections on the basis of the cumulative aggregate growth rate performance of each of them in the past five years, the current achievement in each of them, MNRE/GOI’s 11th Plan targets for capacity addition in RE and the remaining RE potential available in the state, the Commission estimated incremental generation at the state level in 2010–2011. For the sake of uniformity, the capacity added under a specific RE technology was multiplied by the capacity utilization factor for that technology, as per the CERC RE Tariff Regulations, 2009; again, for uniformity, the cost of generation/RE tariff for different technologies for 2009–2010 was assumed to be as per the CERC Tariff Regulations, 2009; in the assessment, the (pooled) APPC for a state represented the weighted average pooled power purchase cost by distribution licensee (excluding transmission charges) in the state during the previous FY (2009–2010). The forbearance price for REC was derived on the basis of the highest difference between the cost of generation of RE technologies/RE tariff and the APPC of 2009–2010 for the respective

140  Renewable Energy in India

states. Floor price was derived keeping in view the basic minimum requirements for ensuring the viability of RE projects set up for meeting the RE targets. The viability requirement covered the loan repayment and interest charges, O&M expenses and fuel expenses in the case of biomass and cogeneration. To keep it short, the approach to calculating floor price for solar technologies is not taken up in detail here. But the approach is broadly similar to that for computing the forbearance price, except that the floor price is derived as the difference between the viability cost for a renewable project (of late taken as 70% of the cost of RE being equivalent to normative debt servicing requirement) and the APPC. From the above, the Commission in June 2010 arrived at the forbearance price for non-solar and solar technologies of `3,900/MWh and `17,000/MWh, respectively. Thus, departing from various prevalent approaches abroad, the Commission has pursued an approach in which these prices are determined with the help of quasi-supply curve for RE generation. Further, the Commission too, like in other countries of the world, has provided for the minimum level of price support in its order to the eligible renewable generators. However, it has arrived at REC floor prices by again using a quasi-supply curve approach; but under different circumstances than those in the case of a forbearance price. The floor price thus arrived is `1,500/MWh and `12,000/MWh, respectively, for non-solar and solar technologies. While this latter price is meant to protect the viability of RE generators under conditions of declining REC prices, it also explains why the CERC’s order has kept solar and non-solar under two different obligation categories. Subsequently, the CERC through a suo motu order in August 2011 revised the floor and forbearance price of non-solar and solar RECs for the control period from 1 April 2012 to 31 March 2017. Through this order, the floor price of the non-solar and solar RECs was kept as `1,500/MWh and `9,300/MWh, while the forbearance prices of the two categories were determined as `3,300/MWh and `13,400/MWh, respectively. Subsequently, in Renewable Energy Certificate (REC)  141

December 2014, the Central Commission revised the floor and forbearance prices of solar RECs to `3,500/MWh and `5,800/ MWh for the remaining part of the control period, that is, up to 31 March 2017, while leaving the floor and forbearance prices of non-solar RECs untouched. From 1 April 2017, the floor prices of solar and non-solar have been pegged at `1,000/ MWh, while the forbearance prices of solar and non-solar RECs have been set at `2,400/MWh and `3,000/MWh, respectively. In a recent order issued in June 2020,2 the CERC has further revised the forbearance price for both solar and non-solar RECs to `1,000/MWh and the floor price to `0/MWh. The forbearance price in the CERC order is akin to the buyout price of REC to be paid by suppliers/DISCOMs in the UK for defaulting on their RPS obligation. In India, the forbearance price is also meant to act as a protection to obligated entities against a runaway rise in REC prices. The forbearance price is required to be high enough to discourage obligated entities from defaulting on their obligations, at least in normal circumstances but, in a scenario where there could be a serious shortfall in RE generation for whatever reasons, the forbearance price is meant to act as a protection against a runaway rise in REC prices.

Eligibility Criterion for Generators There are eligibility criteria for registering as generators under the REC. These require a generating company engaged in generation of electricity from RE sources to register with the central agency for issuance of and dealing in the RECs. Further, at a time of registering, it should not be availing of the benefit of selling such generation at a preferential tariff (determined by the appropriate commission) and, on registration, it should sell electricity so generated to the distribution licensee in its area at a price not exceeding the pooled cost of power purchase of the licensee or to an open access consumer at a mutually agreed price or through market at a

142  Renewable Energy in India

market-determined price. The last of this presumably allows RE generators to take advantage of electricity prices in the spot market if they decide to do so. The central agency for the issuance of RECs is required to issue certificates after satisfying itself that all the conditions for the issuance of certificates, as stipulated in the detailed procedure, have been met by eligible RE generators. The certificates are, in fact, to be issued against renewable units of electricity generated and injected by the generator into the grid after duly accounting for it in the energy accounting system, as per the Indian Electricity Code or the State Grid Code, as the case may be. Each certificate issued, like the ROCs in the UK and elsewhere where this system is in operation, would represent MWh of electricity generated and injected into the grid from an RE source. There are other similarities as well with the RPS implemented abroad. As mentioned in the CERC notification, the price of electricity from RE units is pegged to the weighted average pooled cost of electricity to the distribution entities. This, in effect, is a wholesale price of electricity, as understood in the context of the Indian electricity sector. In pegging the price to pooled costs, the regulator’s intention has been to protect electricity consumers, especially in areas of entities having RPO in which the share of RE in total electricity consumption is disproportionately high. Next, the tradability of REC obviates the need to actually procure electricity from RE generator and thus reduces transaction costs for the obligated entities towards meeting their obligations. Further, since the interstate trade is in RECs and not in electricity, it sidesteps the issue of physical constraints mentioned above. However, as in systems abroad, it is not quite clear whether the order has capped the costs to consumers in the case of a default by the obligated identity. Lastly, most countries that follow the RPS approach for promoting electricity from RE allow for the banking and Renewable Energy Certificate (REC)  143

borrowing of RECs. The former allows holders to keep RECs in their account for compliance with the obligation in the future. The latter, on the other hand, allows the current obligation to be met from the future generation of renewable electricity. However, in the Indian context, obligated entities cannot retain RECs for future compliance. Once traded, the RECs get extinguished. Also, bilateral trades in RECs are not allowed in India. RECs can be traded only in PX. Thus, the tradable certificate mechanism, which has come into effect in India, is in many ways similar to that in operation in several other countries of the world. However, there are several departures in the order, which is meant to adapt this system to the present Indian situation. That said, the RPS as envisaged in the CERC order has aimed at creating a national market for RE in the most practicable manner possible. In this chapter, one may well ask if there are any issues that could come up in the operation of trade-driven RPS mechanism under the Indian situation. The RPS mechanism has already become functional for both non-solar and solar renewable power suppliers for some time now. As things stand, the CERC order has allowed both the RPS mechanism and the preferential tariff system in states to operate side by side, though independently of each other. The order has thus provided the option to both the electricity distribution licensees (in meeting their RPS obligation) and the RE generators to either commit their resources under the REC system or the preferential tariff system. Here, one can try and contemplate the manner in which the order could affect the REC market, especially in states that are well endowed with RE resources. Generally, under preferential tariffs, grid operators are obliged to guarantee priority grid access to RE and are also obliged to buy electricity at regulatory prices from the generators feeding RE into the grid. In contrast, the RPS scheme is designed to aid the RE to compete with conventional energy sources by creating a RPS market.

144  Renewable Energy in India

Further, in the Indian context, since there is a concentration of RE potential in a few states, it could mean that these states could well end up with the bulk of investments in renewable generation capacity under the national obligation system. This could pose challenges to the management of power grids in these states, which they would have to address. Apart from this, one might also want to assess a priori whether the REC mechanism, as envisaged, could achieve the national RE generation target and at what cost. Also, there could be issues concerning risk that would affect states well endowed with RE resources differently than those not so well endowed.

Preferential Tariff versus RPS Mechanism It is apparent that the simultaneous operation of the REC and the preferential tariff mechanism in states which are well bestowed with RE resources have opened up opportunities to distribution entities in these states to seek out the best option from either of these two to meet the RPO. Theoretically, they can choose either to buy RECs from the market or to negotiate a PPA with eligible RE generators if the latter are willing to do so. However, the CERC has foreclosed this choice. It requires the RECs to trade only on PX.3 This rules out the long-term contract market in the REC segment of the RPO mechanism. However, if entities having RPO wish to protect themselves against long-term risks stemming from the volatility in REC prices, they have an option to approach the preferential tariff segment and to sign a PPA with any of the generators operating under this system, at least for part of their needs. Thus, it seems that the preferential tariff segment could well function as a contracts market for obligated entities. The trouble, however, is that the contracts market will be constrained when it comes to the states having inadequate RE

Renewable Energy Certificate (REC)  145

resources and leave obligated entities in them stranded without adequate cover against risk associated with the REC prices if the interstate transaction costs are high and the transmission constraints are binding. While the extent to which obligated entities choose to secure themselves against the risk of defaulting on obligation depends on several factors, it is nevertheless pertinent that they have an option to hedge against risk for the sake of healthy development of market. Looking at the situation from the other side, before committing investment, the RE generators are under no obligation to commit generation capacity either under the state-sponsored RPO systems or the REC mechanism. This gives them some latitude in deciding where to position themselves before investing. However, once they have committed one way or the other, they are not left with much choice in the short term. Those that choose the state-sponsored RPO system have, it seems, no option but to remain tied to it. This, however, is not entirely true. They still have a choice. They can, if the spot electricity prices are sufficiently high, opportunistically participate in the spot market for electricity by reneging partly or fully on their PPA obligation. Were this to happen, it would amount to leakage, since they would forsake a preferential tariff for a higher price of electricity in the spot market, by diverting the supply of electricity away from the obligated entities in the state to the spot market for electricity. This leakage would be difficult to account for in the obligation system since there is no way to distinguish between generation sources once electricity enters the spot market. There is no such issue with generators registered under the REC mechanism. Irrespective of the segment of the electricity they supply, they will receive RECs for all of their generation. These, in turn, will have to be sold on PX to those having to comply with the RPO. RE generation will thus be fully accounted for in the REC mechanism. The separation of the green feature from the commodity aspect of RE and creating a market for trade in RECs ensures that there is no leakage.

146  Renewable Energy in India

The diversions of power generation by RE generators from states’ RPO segment could well affect the REC prices, if the obligated entities, which have not been able to secure their RE obligation in full from the RPO segment, had to resort to purchasing RECs on PX for plugging the shortfall. This could lead to a scramble for RECs pushing up their prices when the additional demand from these sources for the certificates manifests on PX. If the surge is strong, it could well push up the REC prices to the ceiling notified by the CERC. Indeed, the regulator will have to play a role in such situations to prevent runaway rise in REC prices. CERC regulations have some safeguards against such leakage apart from the provision of forbearance price. However, during spells when the spot market for electricity is weak, the REC price would be pushed down. Thus, in the absence of long-term contracts market for RECs, the only safeguard that generators in this segment would have against downward volatility is the floor price ordained by the central regulator. Whether this would prove enough for securing longterm investments required for fulfilling national obligations is a matter of conjecture. This aspect would, therefore, need attention if the REC mechanism is to develop in an orderly manner. Intuitively, allowing a parallel development of long-term contracts in certificates makes sense with a view to encouraging investments in this segment. This would comfort both the obligated entities, which are looking for some minimum risk cover against chances of defaulting, and the RE generators, which are looking for some minimum security against the volatility in their revenue streams. In fact, US experience with the REC system suggests that RE projects generally require long-term sales contracts to obtain financing and deliver energy at a reasonable cost. And in markets where long-term contracts are available, renewable electricity is typically procured competitively and at reasonably low prices.4

Renewable Energy Certificate (REC)  147

Wide Divergence One further issue is a wide divergence between states, both with respect to the overall RE potential and the type of RE resources. For instance, most of the wind potential in India is in states such as Tamil Nadu, Karnataka, Gujarat, Andhra Pradesh, Maharashtra, Rajasthan, Madhya Pradesh and Kerala. Whereas states such as Chhattisgarh, Uttarakhand and Himachal Pradesh have only a moderate RE potential mainly made up of small hydro potential. The remaining states have negligible RE potential, excluding solar. Thus, states having a high or moderate RE potential will, in all likelihood, drive the development of RE power in years to come, as the REC system takes roots nationally. It is apparent from this that the manner in which investments in RE technologies and capacities pan out between the REC and the preferential tariff segments of obligations markets in states across India will not be uniform since resource endowment and their commercial potential will differ. Thus, one expects states with high RE potential to have an obligations market that is loosely structured between their own RPO segment and the national REC segment. In contrast, states with low RE potential will be dependent mainly on the national REC market for meeting their RE obligation. A further complication on the part of distribution entities/consumers is whether high- or low-cost resources dominate the RE potential of their respective states and whether these resources adequately cover their obligation requirements over extended periods in the case that they choose to subscribe to the preferential tariff system in their states. Also, there are states such as Tamil Nadu and Maharashtra, which have significant wind potential, but have already exploited over 50 per cent of it. In contrast, there are states that still have to make the beginning. This disproportionate penetration of renewable generation between states raises an important question: What should be the scheme for apportioning national RE target between them? 148  Renewable Energy in India

Equally, considering that states having significantly large RE resources will, in all likelihood, draw disproportionately high investments in RE power capacities to serve the national REC market, these states will have to be prepared for dealing with the grid stability issues (and perhaps there could be a regional grid stability issue as well) associated with, especially, the intermittent renewable generation. In recognition of this, a report has been prepared by the Power Grid Corporation of India in July 2012, titled ‘Transmission Plan for Envisaged Renewable Capacity’ (Vol. 1). This report has gone into the identification of transmission infrastructure for the likely capacity additions of RE-based power generation capacity in renewable-rich states, estimated the capex requirement for the development of transmission infrastructure in these states and provided a strategy framework for the development of a model for funding transmission infrastructure to facilitate speedy renewable power development.

Market Performance of REC Scheme Over the seven years from 2010 to 2017, 2,265.872 MW of new renewable generation capacities were set up under the REC mechanism. This constituted only 6.75 per cent of the total RE capacity growth over that period. Initially, the scheme did evoke a positive response, but gradually the enthusiasm began to fade away. The number of projects registered under it began to decline (Table 7.1) and its efficacy as an instrument to deliver RPO compliance began to be doubted.5 After the government switched to auctioning as an exclusive mode for identifying and registering developers for RPO-linked wind and solar power projects, the trading in RECs came to a virtual halt. Its future has since looked dim. Almost all through the scheme’s years in operation, demand– supply mismatch prevailed (see Table 7.2). As one would expect, there are, indeed, several explanations for the scheme’s failure in delivering nationwide RPO

Renewable Energy Certificate (REC)  149

RE Generators Registered (No. of Projects and Table 7.1  Capacity in MW as on 31 March 2018) Year

Total No. of Projects

Total Capacity (MW)

2010–2011

10

70

2011–2012

177

1,018

2012–2013

158

711

2013–2014

220

669

2014–2015

136

486

2015–2016

80

263

2016–2017

86

553

2017–2018

38

179

905

3,948

Total

Source: https://www.recregistryindia.nic.in/pdf/Others/Report_on_REC_ Mechanism.pdf

compliance by obligated entities. One of the principal reasons cited has been the conflict between the FIT and the REC mechanisms, which predictably led to the decline of project registrations under the latter. It hence appears that the obligated entities, given a choice between the overall stable costs of meeting their RE obligations from units registered under the FIT regime and those under the REC mechanism chose the former, implying that the more uncertain cost components (due to fluctuating REC prices) of the latter vis-a-vis the former made it riskier than the predetermined FITs option and, hence, less attractive. This suggests that the obligated entities have become accustomed to the risk-free environment and, for the REC scheme to succeed, the REC prices should have been much higher than the upper ceiling fixed on their prices by the regulator in order to compensate for the inherent risk in this traded instrument. Nevertheless, it is common knowledge that the overall RPO acceptance by the obligated entities over the years has remained 150  Renewable Energy in India

0.404

0.089

8.645

2018–2019

0.465

2015–2016

2016–2017

0.101

2014–2015

2017–2018

0.077

0.054

2012–2013

0.014

15.251

3.499

32.370

22.767

3.7

0.586

Solar

57

3

1

2

3

9

549

4.446

0.12

0.153

0.183

0.063

0.014

0.012

45

9

1

2

2

10

265

(Table 7.2 Continued)

9.985

1.368

14.766

9.380

3.346

0.135

0.005

Volume of Volume of Volume of Bus Bid Buy Bid Sell Bid as % of of RECs of RECs Volume of (Million) (Million) Sell Bid

Volume of Volume of Volume of Buy Bid Buy Bid Sell Bid as % of of RECs of RECs Volume of (Million) (Million) Sell Bid

2013–2014

Year

PXIL

IEX

Table 7.2 Demand and Supply of REC (2012–2013 to 2018–2019)

4.215

9.417

8.805

2016–2017

2017–2018

2018–2019

6.043

63.509

98.150

88.992

55.325

25.165

9.185

146

15

4

3

3

5

27

3.782

6.789

1.716

1.653

32.413

59.637

55.088 64.401

1.451

17.233

2.490

1.634

1.411

0.655

Source: http://cercind.gov.in/2019/market_monitoring/Annual%20Report%202018–19.pdf

1.447

2.673

2014–2015

1.271

2013–2014

2015–2016

2.435

229

21

3

3

3

8

26

Volume of Volume of Volume of Bus Bid Buy Bid Sell Bid as % of of RECs of RECs Volume of (Million) (Million) Sell Bid

Volume of Volume of Volume of Buy Bid Buy Bid Sell Bid as % of of RECs of RECs Volume of (Million) (Million) Sell Bid Non-solar

PXIL

IEX

2012–2013

Year

(Table 7.2 Continued)

low across Indian states. This has been mainly on account of the reluctance by the government-owned electricity distribution entities to fully honour their RPOs. This suggests that it is not just under the REC regime but also under the FIT regime the registrations may have been declining. Notwithstanding this, one redeeming feature of the REC scheme has been that the trend in acquiring RECs was not entirely negative across all segments of the obligated entities. In contrast to the public sector electricity DISCOMs, the REC scheme showed far greater promise with both open access and captive buyers, the private sector DISCOMs and the electricity departments of the UTs.6 Nonetheless, since the public sector DISCOMs constituted for an overwhelmingly high share of the total annual aggregate national renewable power purchases, success in smaller RPO segments was not sufficient to upset the declining trend in the former. Could this apathy of state-owned DISCOMs be explained simply by psychological factors7 (such as the REC not being accompanied by real power, hence not having any tangible value)?)While it is difficult to conclusively prove this, there are several other plausible explanations for this. Logically, perhaps it is more appropriate to conclude that managements in the public sector entities lacked skills to assess risk than those in the private sector; or, on the other hand, private sector entities in comparison had no other option but to buy RECs from the exchange in order to meet their RE purchase obligations. Hence, it seems that for the REC mechanism to be successful, it was essential to withdraw the FIT regime and to leave only the former as a means to fulfil RPOs by all entities. Lastly, those subscribing to the ‘psychological’ factor explanation for the failure of the REC mechanism to enthuse public sector obligated entities propose emulating the UK example. The units of electricity were bundled in their tradable product (equivalent of REC) in this country and sold as one in the market by RE generators to obligated entities. However, if one goes back to the original purpose for creating the REC

Renewable Energy Certificate (REC)  153

mechanism, which was to facilitate the obligated entities in RE-scarce resource states to meet their RPO obligations, it is clear that bundling the tangible and intangible product could not have been the solution to the problem. While the idea behind the launching of REC looked promising when it was first conceived, from the hindsight, it might seem to have missed out on certain counts. Considering that there are only a few states with well-endowed RE resources in this country, expecting these few states to install disproportionately large RE power capacities in relation to their own power grids’ size would have proved unduly burdensome to them, causing grid stability issues.

Chapter Conclusion In 2010–2011, a scheme was introduced in India to enable obligated entities in states having scarce RE resources to meet their obligations by purchasing RECs from RE power producers in states well endowed with these resources. The said scheme thus became one of the two modes nationally—the other being FIT—by which obligated entities across the country could fulfil their annual purchase obligations through third-party wind and solar power producers. In this chapter, we examined, among other things, the market mechanism for the REC regime and the overall performance of the REC scheme over the years since its inception. The REC scheme was conceived as a market-based instrument to deliver national obligation targets more efficiently than the prevailing FIT regime. However, market performance does not exude confidence in terms of its continuation in the existing form for long. It’s high time the mechanism was reviewed seriously and, ideally, a sunset clause was drawn up for the smooth transition of projects already registered under this scheme. Having discussed the dynamics of RPO as an instrument for market creation for renewable in the previous chapter and of the REC as a market-based instrument in this chapter, the

154  Renewable Energy in India

natural sequel is a discussion on the appropriate market design for renewable in India. The reason, unlike the RPS of the UK, which has been a combination of the RPO and the renewable obligation certificate with the mandatory participation of renewable projects in the wholesale market for the sale of their electricity component, the RPO and REC mechanism in India did not mandate the participation of renewable in the market, nor did it provide for such certificates as the only instrument for compliance of the RPO. India adopted and continues to adopt the fixed tariff regime—cost-plus or auction-based FIT— for RPO compliance alongside REC as an alternative instrument for RPO compliance. Given these realities, what are the options for India to encourage the participation of renewable in the market and, eventually, mainstream with conventional generators? But before we probe this question, it is necessary to appreciate the special nature of renewable, namely its intermittency. Accordingly, in the next chapter, we discuss this aspect of intermittency and then go on to the subsequent chapter to deliberate on what we consider to be the right market design for renewable in the Indian context.

Notes 1. Central Electricity Regulatory Commission, ‘Order dated 1 June 2010, Petition No. 99/2010 (Suo Motu) in the Matter of Determination of Forbearance and Floor Price for the REC Framework’ (2011). Available at http://www.cercind.gov.in/2011/ august/order_on_forbearnace_&_floor_price_23-8-2011.pdf (accessed on 10 February 2021). 2. http://cercind.gov.in/2020/orders/5-SM-2020-final.pdf (accessed on 1 October 2020), 61–62. 3. Central Electricity Regulatory Commission, ‘Central Electricity Regulatory Commission (Terms and Conditions for Recognition and Issuance of Renewable Energy Certificates for Renewable Energy Generation) Regulations, 2010) (2010). Available at http:// www.cercind.gov.in/2015/regulation/GZT49.pdf (accessed on 10 February 2021). 4. Richard J. Piwko, California Energy Commission, Public Interest Energy Research, General Electric Company, GE Energy

Renewable Energy Certificate (REC)  155

Consulting, California Energy Commission and Energy Generation Research Office, ‘Intermittent Analysis Project. Appendix B, Impact of Intermittent Generation on Operation of California Power Grid: PIER Final Project Report’ (Prepared for California Energy Commission by GE Energy Consulting; Sacramento, CA: Public Interest Energy Research, California Energy Commission, 2007). 5. Sushant K. Chatterjee, ‘The Renewable Energy Policy Dilemma in India: Should Renewable Energy Certificate Mechanism Compete or Merge with the Feed-in-Tariff Scheme?’ (2017). Available at https://www.hks.harvard.edu/centers/mrcbg/publications/awp/ awp79 (accessed on 10 February 2021). 6. Ibid. 7. A psychological barrier in the main text relates to a perception that the purchase of REC is seen by obligated government entities as giving away money without any tangible benefit like getting energy/power.

156  Renewable Energy in India

8

Intermittent Renewable How to Enable Participation in Market?

Introduction Intermittency is often seen as a constraint to market participation of renewable. However, this needs to be overcome not only to mainstream renewable but also to assuage the sentiments of host renewable-rich states that have to face the consequences of such intermittency. This chapter discusses the nature of intermittency, the steps taken by India to address this limitation and the desirable course of action to ensure a smooth transition of renewable to market. If one looks at the projected growth for different types of RE generation resources in the country, one finds that not all of the national RE generation targets will be met by the dispatchable segment of the renewable generation. Rather, a great deal of it will come from intermittent resources, such as wind and solar, which cannot be dispatched at will. This means that the

concerned states would have to make special efforts to integrate these resources into their respective power grids since neither the state nor the regional power grids in India have been designed to transmit asynchronous power in bulk. However, accommodating intermittent generation in power grids that are traditionally not designed for them has been a universal challenge. One can expect similar issues, as others in the world have faced, to surface here also in our state grids once the share of intermittent generation in their total generation crosses the threshold. The challenge of accommodating intermittent generation mainly pertains to its impact on system’s reliability and dispatchability. Particularly, in the case of wind, which has a far greater variability than any other renewable generation unit, since it occurs at night-time, when the system load is light and the flexibility in the system is at its lowest. How serious is the issue? Let’s look at the wind and solar generation profile and compare it against the system demand in some of the renewable-rich states, as shown in Figure 8.1. Figure 8.1 shows the profile of load, and wind and solar generation in Tamil Nadu on the maximum wind generation day, that is, on 22 August 2017. On this day, the combined wind and solar generation was 5,279 MW (4,618 MW wind plus 661 MW solar) and the contribution of RE was to the tune of 34 per cent.1 Variability of the wind notwithstanding, the interesting point is that even on this high-wind day, wind and solar generation were complementary to each other, especially during 09:30 hrs and 15:30 hours (see increasing trend of the black line [wind] and decreasing trend of the light grey line [solar] during this period) and have met most of the load during the day time. The other dimension of this phenomenon is that during high wind + solar generation, non-renewable generation has to be operated at lower capacity level and, in some cases, it has to be backed down. This poses a challenge in managing the steep ramping requirement in the evening when both wind and solar are not available (see the dark grey line [demand] peaking up

158  Renewable Energy in India

16,000

5,000

14,000

4,500 4,000

12,000

3,500

10,000

3,000

8,000

2,500

6,000

2,000 1,500

4,000

1,000

2,000

500

0:30 1:30 2:30 3:30 4:30 5:30 6:30 7:30 8:30 9:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 17:30 18:30 19:30 20:30 21:30 22:30 23:30

0

Demand

Wind

0

Solar

  T amil Nadu State Demand versus Wind Figure 8.1 Generation (22 August 2017)—Maximum Wind Generation Day Source: Based on Annexure VIII of CEA’s Technical Committee Report.2

from 17:30 hrs and solar disappears and wind generation starts declining). You need flexible generation like hydro or gas to manage the high-peak ramping requirement. Similarly, let’s look at the profile of Gujarat on a maximum wind variation day, that is, on 22 May 2017 as depicted in Figure 8.2. Here also, the wind and solar have been complementary to each other. From 07:00 hrs to 11:00 hrs, solar picked up and wind disappeared but again after 11:00 hrs, the trend reversed with wind peaking up and solar steadily declining. But the wind generation witnessed significant variability during the day, and what is also of concern is the sudden dip in the wind generation, say, from 19:00 hrs and the rising trend of

Intermittent Renewable  159

16,000

3,000

14,000

2,500

12,000 2,000

10,000 8,000

1,500

6,000

1,000

4,000 500

2,000 0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Wind Generation

Solar Generation

0

State Demand

  Demand in Gujarat on 22 May 2017, along with How This Was Met from Various Sources Figure 8.2 of Generation Available—Maximum Wind Variation Day Source: Based on Annexure-VIII of CEA’s Technical Committee Report.3

demand during this period, which needs to be met by flexible generation. Generally, as long as the variability of the intermittent generation is lost in the variability of the system load and easily absorbed in the dispatch,4 it is less of an issue. But there is a penetration level beyond which the power systems cannot absorb additional variability inducted by this form of generation, especially during light load periods. Considering that wind power has been growing rapidly and forms a considerable part of the system load in some of the states in India, this issue will have to be addressed. The question is how. Dealing with the uncertainty introduced by the intermittent generation would require the rest of the generation in the system to be responsive to the fluctuations introduced by it. In wind’s case, since its rising generation coincides with that of the

160  Renewable Energy in India

declining load in the system, one of the options would be to build deeper runback capability to mitigate light load manoeuvrability.5 This would, however, be appropriate if the net load (system load less intermittent generation) in the system remains below the minimum system load for a significant number of hours during the year. On the other hand, if the coincidence of very high intermittent generation with minimum system load is infrequent, a better option would be to either let some units de-commit or curtail some wind generation for a brief period of time when this happens. But a problem with de-committing a base load unit is that it may not be available when it is needed most in the future. If that’s the case, it may be economically preferable to curtail wind generation than de-commit a base load unit for the required period. Conversely, de-committing base load units may prove cost-effective if one expects extended periods of significant wind energy curtailment.6 One further issue is managing ramps. This is a major challenge for system operators handling power systems with high penetration of intermittent generation. Generally, automatic generation control (AGC) mechanisms play a major role in managing shortterm uncertainties in power systems. However, with increased intermittent penetration, their performance criteria, capabilities and technologies would require modification for managing added variability in the system due to intermittent generation.

Existing Enabling Framework of System Operation in India Let’s first look at the framework as it exists in the context of power system operation in India with focus on RE.

Scheduling and Dispatch Scheduling is done for the injection of power as well as for the drawl of power, and both these schedules are subject to further

Intermittent Renewable  161

rescheduling. Scheduling requires a smooth and continuous flow of information among stakeholders such as the National Load Dispatch Centre (NLDC), regional load despatch centres (RLDCs), state load dispatch centres (SLDCs), Indian Energy Exchange (IEX), DISCOMs, Inter State Generating Station (ISGS), intrastate generators and others. Typically, RLDC is responsible for scheduling generation for every station under the Inter-State Transmission System (ISTS) while SLDC is responsible for generating stations under the Intra-State Transmission System. Demand estimations are an important activity in the scheduling and dispatching process and hence all SLDCs have the responsibility to estimate the demand for power on a daily to annual frequency basis. Depending on these estimates, the SLDC further formulates its strategies and measures to manage demand. DISCOMs or SEBs are obligated to follow the measures laid down by the SLDC for demand management. The SLDC, along with the distribution licensee, must ensure that there is no over-drawl that violates the deviation limits set under the Deviation Settlement Mechanism (DSM). An automatic demand management scheme is implemented by the SLDC or DISCOM to prevent the over-drawl of power. The regional entities must regulate the generation and the consumer load to minimize the difference between the actual drawl and the scheduled drawl. Failure to keep the deviations under the minimum limit leads to charges as per the DSM. To record the actual interchange of electricity, special energy meters are installed by the Central Transmission Utility and the computation of the actual net injection or drawl of the regional entities as per the 15-minute blocks is done by the RLDC. In the absence of accurate forecasting of RE, there arises an imbalance in the grid. Regulations, therefore, mandate that forecasting for RE must be done by the RE generators themselves or through a lead generator. Scheduling of RE is done on a day-ahead basis with the flexibility of revising it 16 times during the day. The RE generators can either use their own 162  Renewable Energy in India

forecasts or accept the ones produced by the system operator (SLDC/RLDC). The system operator only uses its own forecast to do further planning that is necessary for the balancing of grid operations. The pattern of scheduling is similar as any other non-RE generator.7 The dispatch principle for RE electricity generation states that, barring generation from biomass power plants with capacity of 10 MW and above as well as non-fossil fuel cogeneration plants, rest of the renewable power generated should be categorized as ‘must run’.

Imbalance Handling Scheduling demand or supply cannot be done with 100 per cent accuracy all the time. The difference between the scheduled injection/drawl and the actual injection/drawl is defined as deviation. Deviations lead to imbalances in the grid and, unless they are resolved, the desired grid frequency cannot be maintained and damage to generating and consuming equipment can occur. Buyers and sellers of electricity must adhere to the grid discipline by following the schedules. The DSM penalizes over-drawl and under-injection, and rewards under-drawl and over-injection with certain exceptions.8 The optimal grid frequency that needs to be maintained is 50 Hz and hence the charges for deviation apply when the frequency falls below or moves above 50 Hz. Unlike conventional generators, RE generators are not dispatchable and hence the penalty for their deviations (effectively for inaccurate forecasts) needs a different treatment. RE generators are exempt from any penalty for a forecast error up to ±15 per cent and are subject to a deviation charge beyond that tolerance limit. These limits vary from state to state for intrastate operations. Deviation charges for renewable generators are not linked to frequency. The design of the deviation settlement framework for RE generators eliminates the possibility of gaming since the deviation charges apply to both excess and shortfall in energy. Intermittent Renewable  163

DSM strives to achieve a balanced grid by discouraging large deviations but may not be able to ensure zero deviations all the time. Ancillary services (AS) help restore the grid discipline by providing the necessary regulation-up or regulation-down services when required. They help to fill the gap that arises due to unforeseen generation and load mismatch in a particular time block. At present, these services can be provided by any ISGS whose tariff is approved by the central regulator and have unrequisitioned surplus capacities that can be utilized.9 The nodal agency, NLDC, uses the information provided by the Regional Power Committee (RPC) to prepare the merit order of the list of un-requisitioned surplus capacities (i.e., the portion of the generation capacity not requisitioned by the DISCOM). For regulation-up services, AS providers with surplus capacities are stacked in order to increase variable cost and, conversely, to regulate down services, the stack is prepared in order to decrease variable cost. This scheduled quantum of AS is automatically added to the dispatch schedule of the AS provider. It is possible that the AS provider may deviate from the scheduled generation in which case the charges of DSM apply. The RPC prepares and issues a weekly AS statement along with the deviation settlement statement. An important prerequisite for AS to function is the availability of un-requisitioned surplus capacity with the ISGS at the desired time block. There is a certain degree of uncertainty attached with the availability of such surplus capacities and therefore additional reserves are required to be in place to handle the real-time imbalances. The National Electricity Policy suggests that spinning reserves of 5 per cent must be present at the national level to meet the objective of grid security.10 These spinning reserves are to be divided into primary, secondary and tertiary reserves. Primary reserves of capacity 4,000 MW are suggested to be maintained at the national level as an outage contingency measure. Secondary reserves should be maintained by the region corresponding to the size of their largest unit and, similarly, tertiary reserves should be maintained by the state corresponding to 50 per cent of the size of their largest unit.11

164  Renewable Energy in India

The requirements for these reserves must be estimated by the concerned load dispatch centers on a day-ahead basis. Primary control, which can be called as governor control, is an immediate control mechanism that can deliver the first level of reserve power. This control can be exercised by all generating stations by just ramping up the turbine speed when there is a frequency change. Secondary control replaces the primary control. Secondary control, also called AGC, still at pilot stage in India, uses reserves to balance the frequency. AGC requires a robust communication infrastructure between the load dispatch centers and the generating units to send automatic signals during times of imbalance. Currently, the infrastructure required for AGC to operate is lacking in India and, hence, operators often resort to load shedding to balance the grid. Finally, the third level of control needs to be brought in when the grid has been in imbalance for minutes-to-hours, for example, due to the failure of an entire generating unit. Tertiary control involves manual changes in the dispatch and unit generation commitment, which can help to reinstate secondary control.12

Is the Existing Framework Adequate for Seamless Integration of Renewable? Framework for Scheduling, Forecasting and Deviation Settlement of RE Generation The CERC has notified the framework for the Forecasting and Scheduling Mechanism for Wind and Solar Technologies, which factors in the variable and intermittent nature of such generation. The objective of forecasting by the generator is primarily to minimize deviations from the schedule. The RE generator also has the option of choosing between its own forecast or the site-level forecasting as done by the respective RLDC and to provide its schedule. However, the commercial impact of the deviation from the forecast would have to be borne by the RE generator. This framework was put in place by the CERC in

Intermittent Renewable  165

2015. Since then, there has been a lot of development in the sector. There is an urgent need for alignment of this framework with emerging realities. For instance, wind and solar generators are allowed to revise the schedule 16 times during the day and, once they revise their schedule, it becomes effective from the fourth time block from the time of intimation of such revision. In contrast, with the implementation of the real-time market (RTM) from 1 June 2020, the revision flexibility for others has been amended to seven–eight time blocks from the time of intimation for such revision. There is a need to align this right to revision for both renewable and non-renewable generators and demand for the smooth operation of the power system. The tolerance band of ±15 per cent for deviation of wind and solar generation also needs to be reviewed in view of the growing improvement in forecasting, the establishment of Renewable Energy Management Centres (REMCs) and more so because of the emerging concept of aggregation of wind and solar plants at the pooling station level, which reduces forecasting errors significantly. The penal provisions, especially linkage of the penalty to the PPA rate, also need to be reviewed in view of emerging market conditions. Further, given the integrated nature of the grid, it is desirable that a framework as formulated for grid integration of variable RE sources of wind and solar at the interstate level is also adopted by states for intrastate system.

Relaxation in Deviation Settlement Mechanism The Central Commission, while taking into account the problems of RE-rich states owing to the variability of RE, has provided for additional legroom through relaxation in the deviation limits to 200 MW (for states having installed solar + wind capacity of 1,000 to 3,000 MW) and 250 MW (for states having installed solar + wind capacity exceeding 3,000 MW). Relaxation of the deviation limit is not at all desirable. The grid does not generate electricity and, as such, reliance on the grid (by way of over-drawl from the grid) for meeting real-time

166  Renewable Energy in India

energy needs is nothing but a recipe for grid failure. The solution lies in creating reserves and operationalizing AS for handling load generation imbalances. The CERC has laid out a road map13 for operationalizing reserves in the country, but the question is how to make it a reality. Is the Centre fully prepared in terms of the necessary infrastructure, communication system, measurement tools, appropriate regulatory framework/ incentive structure and are the states geared up to supplement these efforts? Each region needs to maintain secondary reserves corresponding to the largest unit size in the region. As regards tertiary reserves, they need to be maintained in a decentralized fashion by each state control area for at least 50 per cent of the largest generating unit available in the state control area. This would mean 1,000 MW of secondary reserves for the Southern region; 800 MW for the Western region; 800 MW for the Northern region; 660 MW for the Eastern region and 363 MW for the North-eastern region (total approximately 3,600 MW on an all-India basis). Primary reserves equivalent to 4,000 MW have to be ensured at all-India level considering generation outage of 4,000 MW as a credible contingency. This is a deterministic approach; it is also necessary to explore a probabilistic approach to the determination of reserves requirement. Ideally, a robust framework on reserves should be provided in the Indian Electricity Grid Code (IEGC) and all states should follow suit.

Ancillary Services AS are support services to maintain the power system reliability and support its primary function of delivering energy to customers. These are deployed by the system operator over various time frames to maintain the required instantaneous and continuous balance between aggregate generation and load. The CERC has notified the regulations on Reserves Regulation Ancillary Services (RRAS) to restore the frequency level at the desired level and to relieve congestion in the transmission network. The RRAS supports both the ‘regulation-up’ service

Intermittent Renewable  167

(which provides the capacity to respond to signals or instructions to increase generation) and ‘regulation-down’ service (which provides the capacity to respond to signals or instructions to decrease generation). However, the framework operates under an administered mode with an un-requisitioned surplus available in the ISGS. It does not guarantee the adequacy of reserves at all times, especially during peak hours. The need of the hour is to move to the next stage of creating framework for secondary control and market-based procurement of secondary and tertiary AS. It is a matter of grave concern that a power system as big as India’s—with a peak load touching 185 GW and an increase in renewable penetration—is operating without secondary control. What is in place is only tertiary service with no guarantee of the firm reserves in the system. The CERC has ordered pilot on the secondary control/AGC, but that too is limited primarily to thermal generating stations. Reliance on thermal generators alone and closing the door to other resources such as energy storage and demand response to provide secondary response might prove counterproductive and possibly more expensive for India. Absence of communication and metering infrastructure is often cited as the reason for the continuation of administered mechanism in secondary control. But time is running out as renewable penetration is increasing exponentially. Even if it is a guarded movement, a clear road map needs to be laid out—may be under cost-based system to start with and eventually move to market-based procurement of secondary AS—with an adequate incentive for all types of resources to participate and provide fast response, which is so critical for managing variability of renewable. Tertiary services should be thrown open to market immediately, as we have gathered enough experience in the operation of these services under administered mode.

Flexing Thermal Generation The CERC has amended the IEGC, which provides for a technical minimum of 55 per cent in the case of thermal generating

168  Renewable Energy in India

units with a corresponding compensation mechanism for the deterioration of the heat rate, the auxiliary energy consumption and the oil support in excess of the normative parameters. This is aimed at providing flexibility to respond to the needs of variation in demand and RE generation. No doubt, this is a welcome initiative and there is a need for states to align with this requirement for their state-level generators as well. But the manner of allocation of compensation for part-load operation needs to be reconsidered. It is often argued that thermal generators are brought down to the technical minimum for ‘system balancing’, but the costs (additional costs on account of such low loading of generators) are borne by ‘individual’ DISCOMs that have signed contracts with such generators. Here again, the need is to leapfrog from administrative mode to market-based incentive for providing flexibility.

Storage The CERC brought out in January 2017 a Staff Paper on the ‘Introduction of Electricity Storage System in India’. The objective was to brainstorm the issues at stake by placing the paper in the public domain, inviting comments from stakeholders. On the policy and regulatory front, the EA, 2003, covers the generation, transmission and distribution of electricity, but ‘storage/holding’ of electricity is not covered in the Act. Then there are other issues regarding scheduling, energy accounting for charging and discharging, and open access for storage facilities. The CERC paper does give insights into the various aspects of the storage system, but it continues to remain a discussion paper. Storage has a great potential for providing flexibility support and calls for an appropriate incentive for fast ramping. Some headway on creating a regulatory framework for storage has been made, for instance, by recognizing storage including stand-alone storage, as an entity eligible for grid connectivity. Provisions have been made in the RE tariff regulations for cost-plus tariff for renewable with storage. But all this is not considered adequate. The need is to provide a

Intermittent Renewable  169

broad framework scheduling, dispatch and market participation of such resources in the IEGC and in the regulations on AS. India can conceive of mandating the procurement of some prespecified quantum of energy storage by the system operator. This has been tried in other parts of the world, for example, in California.

Smart Grid The IEGC has incorporated elements of smart grid technology that are mandatory, such as automatic demand management, islanding schemes and system protection schemes. Thus, smart grid technologies have a role in the regulations of the CERC. The FOR has brought out Model Regulations on smart grid for suitable adoption at the state level. The objectives of these regulations primarily include enabling integration of various smart grid technologies and measures to bring about economy, efficiency improvement in generation, transmission and distribution licensee operations, manage transmission and distribution networks effectively, enhance network security, integrate renewable and clean energy into grids and micro-grids; enhancing network visibility and access, promoting optimal asset utilization, improving consumer service levels, thereby allowing for the participation in operations of transmission licensees, distribution licensees through greater technology adoption across the value chain in the electricity sector and, particularly, in the transmission and distribution segments. In many states, the process for notifying regulations has been initiated. But we have a long way to go before we could put in place smart grid in the country as a whole. Similarly, distribution system designs would need to be enhanced to accommodate reactive power control requirements, coordinated system restoration, communication between system operators and generators, as well as system protection and safety concerns. Equally, the state-of-the-art forecasting would be required to forecast intermittent generation.

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Interconnection It is pertinent to refer here to a special report on the subject prepared by the North American Electric Reliability Corporation.14 Its findings are also relevant to power systems in India, which in not too distant a future will reach a stage where intermittent generation forms a significant part of their total generation. As the report states, for North America, considerable work will also be needed in India to standardize basic requirements in interconnection procedures and standards, such as the ability of generator owner and operator to provide voltage regulation and reactive power capability; low and high voltage ride-through; inertial response (effective inertia as seen from the grid); control of the MW ramp rates and/or curtailment of MW output and frequency control (governor action, AGC etc.). Indeed, interconnection procedures and standards will have to recognize to a far greater degree the unique characteristics of a wide range of renewable generation technologies while continuing to focus on the overall bulk power system performance. It will be important to have a uniform set of interconnection procedures and standards, phased in over a reasonable time frame, in order to provide greater clarity to equipment vendors and generation developers regarding product design requirements.

Variable Power Supply and Grid Stability The issue of load variability in India’s power system has been present since well before the grid-linked RE generation came into the commercial sphere of the power sector. The source of this variability has been the uneven daily demand pattern that has prevailed in electricity grids of most states. The addition of the grid-linked RE generation has only added to this uncertainty from the supply side. Volatility due to demand fluctuations has usually been managed by conventional measures on supply side, such as

Intermittent Renewable  171

providing quick ramping-up power capacities such as hydropower and, to some extent, gas-based power stations. Besides, some states have taken initiatives also to manage this uncertainty by promoting demand-side management measures from the consumer side. But with the induction of grid-linked RE power units into the system, there would have to be a wider response. While the peaks and valleys in daily demand patterns have characterized the load patterns, these patterns have been well established for most state grids and, hence, the power capacities with rapid ramping capabilities have been able to deal with it comparably comfortably. In contrast, in the case of intermittent RE power, the supply is stochastic and often variable across seasons. The daily load patterns are thus prone to natural fluctuations that may not be entirely predictable. Although the quick response from hydropower and other ramping power stations can provide some relief against this, the unit cost of electricity generated from such ramping stations is high, as these units, unlike conventional power stations, are operated only during the limited time slots when the volatility is high. This requires spreading overhead costs over fewer units of generation from these supply sources, pushing up the unit price for this generation steeply. Although pumped hydropower is a proven storage technology to handle this situation, its deployment in India has, however, remained limited due to competing uses of power, for example, in irrigation. Besides, more worryingly, there is little incentive to build storage, since the time of day is not included in the value of electricity15; as a matter of fact, all electricity supplies are priced uniformly across all day in all states. Also, the total hydro capacity as of now is close to 50 GW, of which 16 GW is linked to the ISTS.16 There are serious environmental and political constraints on expanding this. Yet for achieving accelerated RE growth targets in years to come, it is imperative that reasonably priced storage technologies are developed alongside implementing ‘retail time of day

172  Renewable Energy in India

electricity pricing’ (preferably for 5-minute slots for greater accuracy in forecasting). If one considers the current state of the power sector in India, this will take many years to roll out. It means that though news reports suggest that as a percentage of India’s total power capacity by 2030,17 RE power would constitute half of it, investments in related infrastructure, which have remained sluggish until now, will have to be jacked up significantly in order to ensure grid security. For example, as things stand, the number of installed smart meters in India is at present inadequate. Indigenous manufacturing capability, on the other hand, has been about 25 million meters per year. At this rate, it would take at least 10 years, including communications infrastructure, to replace outdated meters. To accelerate these installations, the government will have to liberalize imports of smart meters while, at the same time, accelerating their manufacturing. Also, the interface boundaries between entities are still not very well defined, and this too would require prompt action. At the same time, a robust, scalable disputefree settlement mechanism, which only a couple of states have at present, will have to be set up in all states that are lagging behind. Over and above, the state-level forecasting and scheduling framework will have to be put in place across all states. The skill set of those responsible for this will have to be improved with appropriate training. All this and much more will have to be done if India is to achieve its ambitious goal of expanding the presence of grid-linked wind and solar capacities in its power system.

Chapter Conclusion India has taken a number of steps to address the issues around intermittency of renewable. Whether or not it is a market, robust forecasting is the first necessary step towards mainstreaming variable renewable. Well, this is a necessary but not sufficient condition. From project developers’ side, efforts must go beyond forecasting accuracy to make themselves firm to the Intermittent Renewable  173

extent possible, say, by means of exploiting the complementarities of wind and solar, or wind and energy storage, or solar and energy storage, or wind and solar with energy storage. This has to be supplemented by efforts from system planners and operators in trying to create necessary infrastructure in terms of communication system, metering, interconnection standards, planning and procurement of reserves and AS, harnessing flexible generation and so on. The question is whether these are preconditions in the absence of which renewable cannot participate in the market. The next chapter on market design seeks to answer this very question.

Notes 1. https://cea.nic.in/reports/others/planning/resd/resd_comm_ reports/report.pdf (accessed on 20 November 2020), 10. 2. Central Electricity Authority, ‘Report of the Technical Committee on Study of Optimal Location of Various Types of Balancing Energy Sources/Energy Storage Devices to Facilitate Grid Integration of Renewable Energy Sources and Associated Issues’. Available at https://cea.nic.in/reports/others/planning/resd/resd_ comm_reports/annexure8.pdf (accessed on 11 February 2021). 3. Central Electricity Authority, ‘Report of the Technical Committee on Study of Optimal Location of Various Types of Balancing Energy Sources/Energy Storage Devices to Facilitate Grid Integration of Renewable Energy Sources and Associated Issues. Available at https://cea.nic.in/reports/others/planning/resd/ resd_comm_reports/annexure10.pdf (accessed on 11 February 2021). 4. North American Electric Reliability Corporation, ‘Special Report: Accommodating High Levels of Variable Generation’ (2009). Available at https://docs.wind-watch.org/NERC-accommodatingvariable-generation_17Nov08.pdf (accessed on 11 February 2021). 5. Ibid. 6. Ibid. 7. Forum of Regulators, ‘Forecasting, Scheduling, Deviation Settlement and Related Matters of Solar and Wind Generation Sources) Regulation, 2015’ (2015). Available at http://www.forumofregulators.gov.in/Data/study/MR.pdf (accessed on 11 February 2021).

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8. CERC (Deviation Settlement Mechanism and Related Matters) Regulations, 2014. 9. CERC (Ancillary Services Operations) Regulations, 2015. 10. Ministry of Power, ‘National Electricity Policy, 2005’ (2005). Available at http://powermin.nic.in/en/content/national-electricitypolicy (accessed on 11 February 2021). 11. CERC Order in Suo Motu Petition No. 11/SM/2015, Roadmap to Operationalise Reserves in the Country, 2015. 12. Ibid. 13. http://cercind.gov.in/2015/orders/SO_11.pdf (accessed on 1 October 2020). 14. North American Electric Reliability Corporation, ‘Special Report’; Power Grid Corporation of India, ‘Transmission Plan for Envisaged Renewable Capacity—A Report’ (Vol. 1; Gurgaon: Power Grid Corporation of India, 2012). 15. Tongia and Gross, ‘Working to Turn Ambition into Reality’. 16. Forum of Regulators, ‘First Report of FOR Technical Committee on Implementation of Framework for Renewables at the State Level’. 17. Bloomberg report in Business Line, 3 July 2019.

Intermittent Renewable  175

9

Market Design for Renewable Energy Right Design, A Missing Link in India

Introduction India is an emerging economy and, given the deep interlinkage between economic growth and the development of the power sector, there is a lot of policy focus on measures to improve efficiency and economy in the power system operation. Market design in the context of power sector is all about this core aspect of efficiency and economy. The objective is to design the market in such a way as to ensure the efficient operation of generation and transmission assets and thereby minimize cost for market participants. However, given the special nature of the electricity system in terms of the requirement of ensuring the security and reliability of the grid operation, the objective function of the economy or cost minimization is always subject to security constraints. It is in this context that the issue of

intermittency of renewable, which poses reliability and security challenges to the grid operation (discussed in the previous chapter), assumes importance. The challenge is to design a market in such a way that the variability of renewable is duly factored in while achieving the overall economy of operation. Pertinently, power market design as a whole is a vast subject unto itself and beyond the scope of the present discussion. The focus of this chapter is on the market design aspect from the point of view of renewable.

Issues RE is distinct from conventional generation in two fundamental aspects: (a) RE has to be consumed when and where it is available while conventional generation can be adjusted (to a certain extent depending on the technology and subject to appropriate costs); (b) even if the RE generation can be forecast with high accuracy (e.g., comparable to the load forecasts), it can still vary over time substantially and force the rest of the power system (i.e., not only supply but also demand side) to adjust appropriately to ensure grid stability. Large-scale penetration of renewable is, therefore, likely to cause disruption if the business-as-usual way of planning, building and operating the power system does not undergo a paradigm change. The challenges thrown by renewable are global phenomena now. In the context of market design, apart from intermittency, rapid changes in the cost dynamics of renewable across the globe have also added new complexities. Liebreich1 talks of the age of base-cost renewables when the costs of renewables, namely solar and wind, have become cheaper than those of the conventional sources of energy. Accordingly, wind and solar tend to become the natural choice for new investment. But this creates new challenges for renewable. Projects based on RE sources need cheaper debt and assurance of revenue on a longer time horizon. Further, solar and wind resources are uncertain and, therefore, their generation depends on other technologies, namely storage, demand response and fossil fuel-based flexible Market Design for Renewable Energy  177

generation facilities that can be put to service to match the variation in the availability of wind or sun. Given the increasing emphasis on renewable across geographies, we are possibly approaching a zone where technologies other than renewable would need subsidies and protection for growth. The base-cost phenomena and the variability of renewable are, therefore, the two fundamental issues that need detailed analysis in the context of the discussion around market design for renewable. How do these factors influence power markets? What adjustments are required in market design for integrating renewable? These are some of the questions that we seek to probe in the subsequent sections. To start with, we take a glimpse of the market models that have evolved in the major economies of the world, seeking to address the two fundamental complexities posed by renewable. Then, we analyse the Indian market model against this backdrop.

Market Models in Major Economies The USA and Europe provide two distinct market models. Let’s look at their salient features first. US market model is often referred to as the standard market design. It postulates a centralized pool-based market where buyers and sellers converge to meet their demand for power or to sell their output. This market operates on a day-ahead time horizon followed by real time, which is closer to the time of dispatch. The least cost generation resources are dispatched to meet the demand. The marginal generator generally sets the uniform market-clearing price. To this is added the transmission loss and congestion amount to arrive at the price at each node and is called the locational marginal price (LMP). LMP and financial transmission rights are used as instruments for congestion management. The unique feature of the US market model is that the system and market operations are handled by a single entity called the ISO or regional transmission organization (RTO). Energy and AS are co-optimized to achieve an economy of operation. Apart from energy only day ahead and RTM, some ISOs/RTOs also 178  Renewable Energy in India

run the capacity market to ensure the availability of adequate capacity to meet loads at all times.2,3 In contrast, the European model does not mandate a centralized market; nor does it require system and market operations to be handled by a single entity. Rather, most European markets have the separation of these two functions—power trades take place bilaterally or through PX, and system operation is handled by the system operator. The last-mile imbalance energy market is generally handled by the system operator. For instance, in the UK, market participants have full freedom to trade and to correct their position until the gate closure which is one hour before the actual time of dispatch. After gate closure, the system operator takes over and balances the energy and reserves requirement through the balancing market. There is no concept of co-optimization of energy and AS. Europe follows zonal pricing as against the locational pricing model of the USA. Also, the concept of capacity market in the form as prevalent in the USA is not there in Europe.4 Given this overview, the question is how does the inclusion of variable renewable impact the market design and to what extent have the market models of the USA and Europe evolved to adjust to the new regime of high penetration of RE. While the previous chapter discussed the need for adjustment in the power system operation to integrate variable renewable, the focus of the present chapter is on the nature of the adjustment needed in the market design to accommodate renewable. The two distinct impacts of a high RE share on a market design are the volatility of prices and the requirement of increasing level of reserves. The marginal cost of generation of wind and solar could be zero or negative (negative to the extent of production tax credit [PTC]) and thus renewable figures at the top in merit order for dispatch. With the higher penetration of such energy resources, the overall marginal price of the system slides down substantially during hours of wind and solar being available for generation, whereas during periods of no wind no solar, market prices could go through the roof as

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the other available resources would tend to price their output high enough to recover their full cost during these times. It is argued that such volatility could have the fallout of rendering renewable as well as non-renewable unattractive for investment in the long run, especially for non-renewable recovery of investment becomes a major issue leading to capacity crisis in the system. It is this reality that has brought to the prominence new dimensions, such as scarcity pricing, uplift price, out-of-market payment and the capacity market, in the context of standard market model of the USA. The second impact is in terms of requirement of a higher level of reserves and the peak management challenge to match the variability and uncertainty of wind and solar. For instance, in a system with high wind and solar generation, the net load (load minus the wind and solar generation) bellies down during the day and witnesses a steep and sharp increase in the evening—taking the shape of a duck curve (see Figure 9.1). Such sharp variation in the morning and evening hours makes market operation quite challenging, especially in geographies where market operation and system operation are separated. Added to this is the sudden fall and rise of wind and solar generation—which could happen any time during the day/night— thereby requiring a higher quantum of reserves in the system for balancing. This has added new thrust to balancing market and AS markets for the procurement of reserves. In this context, co-optimization of energy and AS has also assumed greater significance as a necessary component of market design to achieve the economy and the efficient utilization of existing resources. To summarize, markets across the globe are gradually aligning themselves to the new norm of renewable. Price volatility and missing money problem (the problem of generating companies not being able to recover their costs due to price volatility and the persistent phenomenon of zero or negative price in the market) are being managed through hedging mechanisms like capacity contracts in the emerging capacity market separate from the energy only day ahead and RTMs and through

180  Renewable Energy in India

210,428

202,370

194,442

202,824

193,251

205,410

179,576

205,389

160,944

204,551

145,994

205,204

138,270

208,052

137,089

210,331

141,387

209,487

147,450

207,161

156,866 172,849 194,161 198,788

188,704

194,771

188,935 191,234 194,416

1 140,000

160,000

180,000

200,000

220,000

240,000

196,870

Demand (MW)

203,675

2

200,324

3

196,901

5

195,354

6

192,553

4

199,412

7

204,988

8

205,598

9

205,194

100,000

220,798

Source: Based on Exhibit 5.2 of CEA’s National Electricity Plan.5

215,431

120,000

225,751

211,313

Figure 9.1 All-India Demand and Net Demand of a Typical Day (in 2021–2022)

221,086

Net Demand (MW)

207,866

Total Demand (MW)

217,790

Hour

207,171

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

215,702

financial derivatives in the derivates market. Steep peak, a natural consequence of high renewable, is being managed through encouraging flexible capacity. The market incentive for flexible operation is being extended through energy as well as AS pricing strategies. The requirement of reserves has been increasing with an increase in the share of renewable. This is being managed by bringing organized markets closer to real time—gradually transitioning to 5-minute market from an hourly, half-hourly or 15-minute market. The closer the market operates, to the actual time of dispatch, the less is the reliance on reserves. Added to this is the initiative on enhancing the robustness of AS market and the co-optimization of energy and AS in time horizons ranging from day ahead to real time. AS include primary, secondary and tertiary services and resources like demand response, and energy storage is being encouraged gradually to participate in these markets.6

Indian Market Model Given the overview of global market models, this section discusses the market design aspect in the Indian context. The two fundamental issues discussed in the preceding sections are the base-cost phenomenon of renewable as well as the variability of renewable. The phenomenon of ‘base-cost RE’ has already occurred in India as well, as seen from recent auctions to procure solar PV and onshore wind in India, which have yielded prices of `2.44/kWh and `2.64/kWh, respectively—both significantly lower than a large amount of existing coal thermal generators in India that are using cheap domestic coal.7 Efforts undertaken by policymakers and regulators over the last 15 years have resulted in several major improvements in the power sector, for example, the creation of a national-level PX for a day-ahead energy market with transmission congestion being reflected through the price estimation in 13 zones across the country. The day-ahead became truly national in its scope when the entire national grid was fully synchronized to one frequency in 2014. The steadily increasing stringency of evolving 182  Renewable Energy in India

grid balancing mechanisms (i.e., starting with the UI to today’s combination of DSM and a limited AS market) has led to the grid frequency becoming increasingly stable, while the cost of doing so continues to decline. The outcomes of these initiatives are easy to assess, for example, the prices discovered in short-term trading activities, that is, traders and PX, have been steadily trending downwards over the last decade (see Figure 9.2). The unintended consequences of these transitions despite several major initiatives undertaken by Indian policymakers have started manifesting in various ways. Take, for example, the notional surplus electricity that several states appear to be struggling with. In aggregate, today, there is more base load generation capacity in India (i.e., ~199 GW of coal thermal, ~7 GW of nuclear) than peak demand met (i.e., ~184 GW), let alone the non-base load capacity such as ~45 GW of hydro, ~25 GW of gas turbines and ~87 GW of renewables (as in February–March 2020).9 Further, there is at least ~55 GW of captive generation capacity (as on 31 March 2018) that has been installed by large customers (typically industrial) because of the irregular nature of the grid supply.10 Several thousand MW of capacity in India—coal and gas—are sitting idle (~46 GW)11 as there are either no buyers for their power while several households (~50 million)12 are still un-electrified. In addition, rapidly growing RE capacity is also getting curtailed on a regular basis in different parts of the country. The question that we seek to address here is whether these developments demand change in the market design that exists in India. When we talk about market design, generally we refer to the centralized market primarily involving the electronic platform of PX as in Europe or the central pool as operated by the system operator in the USA. In the case of a central pool, the incidence of price volatility becomes more prominent. The reason is that both generation and load go through the central pool; low-cost renewable remains at the top of the merit list; other generation resources get relegated on the despatch list during hours of high wind and high solar; again, in hours when wind and solar are not available, the market tends to rely Market Design for Renewable Energy  183

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

Price of Electricity transacted through Traders (`/kWh)

Source: Based on CERC’s Market Monitoring Report.8

Price of Electricity transacted through PX (DAM + TAM) (`/kWh)

Year

2008–2009 2009–2010 2010–2011 2011–2012 2012–2013 2013–2014 2014–2015 2015–2016 2016–2017 2017–2018 2018–2019 2019–2020

Figure 9.2  Short-term Trading Price Trends

Price (`/kWh)

2.40

2.30

1.80

4.50

Long-term Transactions PX Transactions Bilateral transactions through traders Bilateral transactions between DISCOMS 89.00

Transactions through DSM

  Share of Market Segments in Total Electricity Figure 9.3 Generation, 2019–2020 Source: Based on CERC’s Market Monitoring Report.13

heavily on non-renewable resources. All of this, in turn, leads to high price volatility. However, in market models where you do not have a central pool, this phenomenon of price volatility does not look that sharp. It is in this context that the Indian Power Market model assumes importance. In India, we still have about 90 per cent of the total generation capacity tied up under long-term PPAs. Only about 10 per cent of the generation gets transacted through a short-term market. To be specific, in so far as transaction through electronic PX is reserved, the share of this segment is only a miniscule 4.5 per cent of the total generation in the country (see Figure 9.3). The question, therefore, is whether India can stay relaxed and not worry about the price volatility in the market, given its small size, even in the wake of large-scale penetration of renewable. In this context, it would be pertinent to look at

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some statistics on the overall price fluctuations in the PX segment of the market occurring in the country. There is a wide variation in minimum, maximum and average prices during a day. Similarly, time block-wise price variation is also seen every day, as is evident from Figures 9.4–9.6. The above figures show hourly variation in prices during a day, week and month in one of the PX, that is, IEX. Prices peak during the morning and evening hours. The price volatility of the PX is also calculated by the CERC in the annual reports of the Market Monitoring Cell using the daily data for the year. For instance, price volatility in the IEX and PXIL for 2019–2020 has been worked out to be 9.36 per cent and 11.07 per cent, respectively.14 01–11–2020

3,500.00 3,000.00 2,500.00 2,000.00 1,500.00 1,000.00 500.00

2000–2001 2001–2002 2002–2003 2003–2004 2004–2005 2005–2006 2006–2007 2007–2008 2008–2009 2009–2010 2010–2011 2011–2012 2012–2013 2013–2014 2014–2015 2015–2016 2016–2017 2017–2018 2018–2019 2019–2020 2020–2021 2021–2022 2022–2023 2023–2024

0.00

Price Variation in Power Exchange during a Figure 9.4  Typical Day Source: Based on data extracted from the website of IEX.

186  Renewable Energy in India

5,000.00

Week Avg 24 Oct to 31 Oct 2020

4,500.00 4,000.00 3,500.00 3,000.00 2,500.00 2,000.00 1,500.00 1,000.00 500.00 2000–2001 2001–2002 2002–2003 2003–2004 2004–2005 2005–2006 2006–2007 2007–2008 2008–2009 2009–2010 2010–2011 2011–2012 2012–2013 2013–2014 2014–2015 2015–2016 2016–2017 2017–2018 2018–2019 2019–2020 2020–2021 2021–2022 2022–2023 2023–2024

0.00

  Price Variation in Power Exchange during a Figure 9.5 Week Source: Based on data extracted from the website of IEX.

The question is whether these price fluctuations are due to renewable. No, not yet. Most of these incidences of price fluctuations have been caused largely by fluctuation in the demand or transmission congestion. 15 While the data as explained above show that India has not yet witnessed high price volatility because of renewable, it does not mean that the Indian power market will remain untouched by the onslaught of renewable. Whether or not through the central PX market the increasing penetration of renewable is likely to impact the power system operation as well as the price trends in the market. The only difference would be that if India continues to operate under decentralized scheduling—with the predominance of self-scheduling it is at present—the impact

Market Design for Renewable Energy  187

4,500.00

Average MCP for period 21 Oct to 22 Nov 2020 for IEX

4,000.00 3,500.00 3,000.00 2,500.00 2,000.00 1,500.00 1,000.00 500.00 0.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

  Price Variation in Power Exchange during a Figure 9.6 Month Source: Based on data extracted from the website of IEX.

in terms of price volatility and the increasing requirement of reserve and AS would be felt in a decentralized manner by individual states. Some states have already started experiencing challenges as a result of high levels of renewable in their geographies, as is evident from Figures 8.1 and 8.2 presented in Chapter 8. Clearly, load management for a state becomes challenging when it operates in isolation only with its own portfolio of generation resources. It is, therefore, desirable that the balancing area and the size of market in India are enlarged from the state level to the regional level and, ideally, to the national level. It is common knowledge that the larger the scheduling and balancing area and the larger the market size, the greater is the resilience of the system and the greater is the scope of efficiency and economy of the power system operation.

188  Renewable Energy in India

The Central Commission in India has already come up with a discussion paper on Market Based Economic Dispatch (MBED)16 which seeks to create a central pool for despatch of generation based on merit order. It is a big game changer, given the contract pattern that exists in the country. The paper has recommended the implementation of this framework for greater efficiency and economy in the power market. While it may take time before political consensus is evolved around the framework, the question is whether there is scope for improvement in the existing wholesale market design even when its size is small. Can it be suitably tweaked to seamlessly integrate renewable in the future? We believe that, given the likely benefit of a larger market for efficient system operation, the procurement of renewable in the future should be strategized in such a way as to encourage them to participate more and more in the larger pool of the market so that the impact of variability in terms of price spikes and the requirement of maintaining reserves gets spread and socialized. It is with this realization that the next section recommends what is considered a desirable future market design in India for integrating large-scale renewable.

Recommended Market Design for RE in India The natural question that follows from the above discussion is what kind of market design is best suited for the integration of large-scale renewable. We discussed earlier that the most relevant economic principles are—larger markets are better than smaller markets—in terms of number of market participants, transactions, liquidity, etc.; faster markets are better than slower markets for minimizing imbalances in demand and supply; centralized auctions for incentivizing the creation of sufficient flexible capacity, scheduling existing generation and balancing the grid as opposed to a purely bilateral contracting-based market structure as it better minimizes cost to consumers; the separation of physical and financial aspects of the contracting Market Design for Renewable Energy  189

increases the possibility of accessing the broadest range of risk management tools.17 Centralized dispatch-based market mechanism not only enhances the economy and efficiency of the operation of generation resources but also helps to integrate renewable seamlessly. However, given the variable and intermittent nature of renewable, it becomes difficult for them to participate in the market, unlike conventional generators. Does it then call for special rules for the participation of such variable generation in the market? The international experience discussed in the preceding section reveals that renewable generators participating in the day-ahead market are treated at par with conventional generators and that no separate carve-out is created for them in the energy market. They get priority in dispatch by virtue of their being zero marginal cost generation. Given that, in the energy market, the marginal generator (i.e., the generator with the highest variable cost) sets the market-clearing price, the RE generators gain by way of earning a difference between the market-clearing price and their short-run cost of generation. In some states in the USA, renewable generators are given incentive by way of a PTC that enables them to bid negative prices. They can make a negative bid to the extent of the PTC. Another important feature of this market is the prevalence of RTM closer to the actual time of dispatch. The RTM framework gives market participants an opportunity to correct their dayahead position by buying and/or selling to make good their shortfall or surplus. This reduces the risks emanating from the variability of load as well as generation based on wind and solar. In India, we already have a day-ahead market in PX that follows centralized economic dispatch principles. However, the share of this market segment is only about 4–5 per cent of the total electricity generated in the country. Further, RE generators have still not been participating in this market segment. Rather, there have been requests for creating a separate segment for Green Power Market, with special dispensation, such as the flexibility of schedule revision during the day and the waiver

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of transmission charges and losses.18 It is important to note that the nature of the collective transaction in the day-ahead market is such that it does not leave any scope for schedule revision. Further, given the declining trend of prices for both wind and solar through competitive bidding, the rationale for the waiver of transmission charges and losses has lost relevance. There is already strong resentment in the DISCOMs against special dispensation for RE generators, as the financial impact of such concessions is ultimately passed on to them. As such, any market framework created on preferential treatment for renewable would be counterproductive. The other argument extended for a separate Green Market is that it will provide another option for obligated entities to meet their RPO. It is worth noting that most obligated entities enter into a long-term PPA to comply with their RPO. Therefore, expecting them to go to the Green Market on a daily basis to meet their RPO appears far-fetched. Further, given that RPO compliance is enforced on an annual basis, most obligated entities generally look for any other mode of RPO fulfilment (other than long-term PPA) only towards the end of the FY. Hence, the creation of a separate Green RE Market segment is not likely to have adequate liquidity and hence cannot sustain for long. Recently, one of the PXs requested the Central Commission for the approval of a new product in the Term Ahead Market (TAM), namely the G-TAM. TAM is, in fact, a bilateral market on the PX platform where one-to-one matching takes place. One-to-one matching of renewable generators and DISCOM is definitely a feasible solution. The Commission has already granted approval and this market has started operating, though on a small scale.19 The Central Commission has also taken another important step in the recent past by introducing the RTM framework20 with effect from 1 June 2020. It is a half-hourly market based on the principle of collective transactions. There are, therefore, 48 market runs during the day. This is an ideal platform for RE generators. This was, in fact, a missing link in the Indian power

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market design. Now RE generators, if they choose to do so, can participate in the day-ahead market and correct their position in the RTM. Else they can choose to participate only in the RTM. In the RTM, they need to forecast accurately only one and a half hour before the actual time of delivery. This is already a norm as per the regulatory framework created by the CERC for forecasting, scheduling and deviation settlement of wind and solar. It is high time that RE generators made the best use of this market platform to optimize their portfolio. There is, however, an issue around the contracting pattern with RE generators prevalent in the country. Most RE generators are wed-locked with the DISCOMs for the entire output from their generator plants. While this gives them the comfort of cost recovery, in some cases, they also feel constrained because of the curtailment of their power on commercial considerations by the DISCOMs. The way forward could be as follows. Those generators, which have a window in their contract for the sale of surplus power at their discretion, can go to this market (RTM) and sell such surplus power at a short notice. In respect of fully contracted generators, the DISCOMs which have entered into a long-term PPA with such generators can make use of the RTM framework as portfolio players and manage variability of load as well as RE generation. In other words, in the event of the RE generation being more than their requirement, the DISCOMs can sell such surplus RE generation to the RTM instead of backing them down on grounds other than technical and security reasons. On the other hand, in the event of such generators falling short of output as against their forecasting, the DISCOMs can lean on the RTM and buy power from there to make good their shortfall. For future RE capacity addition, a mechanism like contract for difference (CFD; as prevalent in the UK) can be tried. A central agency (say, the SECI) could invite bids for central procurement. The tariff discovered should be treated as a reference/strike price for the purpose of CFD. On a day-ahead basis, the selected developer could be asked to go to the PX and sell its power like any other conventional generator. If the price 192  Renewable Energy in India

received by the RE generator from the market is higher than the reference/strike price, the gain over and above the reference/strike price could be refunded by such generator to the central agency. On the other hand, if the price received by the RE generator from the market is lower than the reference/ strike price, the loss vis-a-vis the reference/strike price could be compensated to such generator by the procuring agency. The final adjustment can be done on a monthly/annual basis. Given the price trends in the PX and the prices discovered for wind/solar, it is felt that the central agency will generally not be in deficit (See Box 10.1 in Chapter 10). However, in the event of a shortfall, the same can be considered for socialization. For existing projects as well, this mechanism can be tried. The option of CFD could be given to RE generators by the DISCOMs that have already entered into PPAs with such generators. The role as envisaged for the central agency needs to be played by the DISCOMs. The advantage with this market-linked procurement of renewable is that renewable generators will have the comfort of a fixed price contract while, at the same time, learning how to participate in the market and manage other risks arising out of the forecasting error and the deviation from the schedule as these consequences will have to be borne by them. Eventually, this will lead to encouragement of innovations seeking to reduce variability, say, through better forecasting, harnessing battery storage, etc. As regards price volatility and reserves requirement, yes, these are likely consequences. However, as stated earlier, the impact would be less severe than under the decentralized mode of market operation and procurement by DISCOMs individually as at present. As regards price fluctuations, during the hours of RE generation, market prices will dip because of the influx of lower variable cost of RE generation and, on the other hand, prices will rise when these generation sources are not available. The other caveat is that if, as a result, of the participation of RE generation in the market, only supply side increases without a

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commensurate increase in demand, there would be adverse consequences for existing conventional generators as they would not get dispatched and eventually be rendered stranded. But it is expected that with a reduction in market prices and a gradual introduction of MBED, the demand side will also witness a surge in the day-ahead and RTM. While declining market prices with the participation of renewable might attract demand, the fallout is that this will lead to an increase in the burden for the CFD contract holders, like the central procuring agency or the DISCOMs, in terms of the liability to pay the difference between the strike/contract price and the market price. Suggestion has already been made that, for a specified target capacity, this could be supported through socialization. However, our estimate is that the impact would be much less than the current dispensation of the waiver of transmission charges and losses for wind and solar (see Box 10.1 in Chapter 10). On the market design part, however, there would be a need for further refinements. The current half-hourly RTM needs to graduate to a 5-minute market; AS market needs to be developed on priority, suitably rewarding ramping and flexibility; this should specifically include demand response and energy storage as eligible entities for participation; gradually, energy and AS should be co-optimized; capacity contracts with specific attributes of mandatory availability in the hours of need and forward contracts need to be introduced to hedge against capacity shortage and price volatility; financial derivates though under the jurisdiction of the Securities and Exchange Board of India should be encouraged as hedging instruments. In the last chapter that follows, the aspect of market design is further elaborated in the larger canvas covering other aspects of renewable integration. In fact, the last chapter is a synthesis of the entire gamut of issues discussed in the preceding chapters.

Notes 1. Michael Liebreich, ‘Six Design Principles for the Power Markets of the Future—A Personal View’ (New York, NY: Bloomberg New

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Energy Finance, 2017). Available at https://assets.bbhub.io/professional/sites/24/2017/05/Liebreich-Six-Design-Principles-forthe-Power-Markets-of-the-Future.pdf (accessed on 12 November 2020). 2. Richard Green, ‘Electricity Wholesale Markets: Designs Now and in a Low-carbon Future’. The Energy Journal 29, Special Issue No. 2 (2008); Paul Joskow, ‘Lessons Learned from Electricity Market Liberalization’. The Energy Journal, Special Issue (2008). The Future of Electricity: Papers in Honor of David Newbery. 3. E. Ela, M. Milligan, A. Bloom, A. Botterud, A. Townsend and T. Levin, ‘Evolution of Wholesale Electricity Market Design with Increasing Levels of Renewable Generation’ (Technical Report NREL/TP-5D00-61765; Golden, CO: National Renewable Energy Laboratory, 2014). 4. Green, ‘Electricity Wholesale Markets’; Joskow, ‘Lessons Learned from Electricity Market Liberalization’. 5. Central Electricity Authority, ‘National Electricity Plan’ (Vol. 1). Available at https://www.cea.nic.in/reports/committee/nep/ nep_jan_2018.pdf (accessed on 11 February 2021). 6. https://energyinnovation.org/publication/wholesale-electricitymarket-design-for-rapid-decarbonization/ (accessed on 1 October 2020). 7. http://pib.nic.in/newsite/PrintRelease.aspx?relid=161755; http://seci.co.in/web-data/docs/L1%20tariff%20 as%20discovered%20after%20e-RA(2).pdf (accessed on 11 February 2021). 8. CERC, ‘Market Monitoring Report’ (New Delhi: CERC, 2019–2020), Figure 9. 9. http://cea.nic.in/reports/monthly/executivesummary/2020/ exe_summary-03.pdf (accessed on 11 February 2021). 10. http://www.cea.nic.in/reports/monthly/executivesummary/2017/ exe_summary-01.pdf (accessed on 11 February 2021). 11. http://www.financialexpress.com/economy/46-gw-powergeneration-capacity-lacks-last-mile-connectivity-phdcci/606037/ (accessed on 11 February 2021). 12. https://www.bloomberg.com/news/features/2017–01-24/livingin-the-dark-240-million-indians-have-no-electricity (accessed on 11 February 2021). 13. CERC, ‘Market Monitoring Report’, Figure 12. 14. CERC, ‘Market Monitoring Report’. 15. http://cercind.gov.in/2020/market_monitoring/Annual%20 Report%202019–20.pdf (accessed on 1 October 2020), 36.

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16. http://cercind.gov.in/2018/draft_reg/DP31.pdf (accessed on 1 October 2020). 17. A common feature of well-functioning commodity markets is that market participants seek to manage their exposure to market risks (among others) through a variety of forward trading arrangements. In the first instance is the physical market that produces short-term prices that represent the balance at the time the physical commodity changes hands. During periods when supply is plentiful relative to demand, the price is usually driven down to the variable cost of the last producer to clear the market. During periods when supply is scarce relative to demand, prices rise to the what the last buyer to clear the market is willing to pay to have access to it at that time, rather than foregoing or postponing access. In both cases, the price is—or should be—the product of healthy competition between suppliers, the difference being that, in the latter case, the price will include longer term costs (investment and other ‘fixed’ costs) suppliers incur to have product available when consumers wish to purchase it. Producers and wholesalers usually seek to protect themselves to some extent from the risks they would face during these periods of surplus and scarcity by ‘hedging’ those risks in effect by buying insurance of some kind. Market participants can and do enter into forward physical transactions of various kinds—bilateral long-term contracts—for instance, between a producer and a wholesaler for the delivery and acceptance of physical commodity over a given period of time at a given price. The problem with reliance on the physical market alone to provide risk management tools is that its liquidity (the volume of transactions available to all parties willing to participate) is inherently limited to the physical amount of the commodity produced and consumed. In order to relieve this constraint, financial markets have developed over time in response to demand for risk management options in which the risks inherent in the underlying physical market can be disaggregated and traded between counterparties for whom transactions are mutually beneficial. This can take place bilaterally (over the counter) or through open trading exchanges. The counterparties to these trades can certainly be the same parties that participate in the physical market, but the skids of the financial trading markets are really greased by the participation of financial intermediaries, often banks and trading houses, which seek to earn a profit by taking on (for a price) and managing certain risks faced by physical market participants more efficiently than those participants

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could manage by themselves. These can be speculators betting on outcomes, but far more often they are traders who themselves find other counterparties to whom they can trade away the risk. As the period governed by a given trade draws closer and closer to real time, prices in the two markets tend to converge, becoming equal on the date the trade matures. Designed correctly, electricity markets are meant to allocate risk in an efficient way. Well-functioning markets in other commodities allocate risks – relying on buyers and sellers of the commodity facing opposite but roughly equal risks for which they are motivated to seek insurance, through both physical and more liquid financial forward trading. 18. http://www.cercind.gov.in/2017/orders/187N.pdf (accessed on 1 October 2020). 19. http://cercind.gov.in/2020/orders/25-MP-2019.pdf (accessed on 1 October 2020). 20. http://cercind.gov.in/2019/regulation/1.%20Statement%20of%20 Reasons_RTM_12_12_2019.pdf (accessed on 1 October 2020).

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10

Renewable Policy Introspection Rethink and Move in the Right Direction

The aim of this chapter is to synthesize the issues highlighted through the seams of previous chapters and to make recommendations and suggest a way forward by putting different parts into a single whole. We start by recounting the issues.

RPO A major issue in the implementation of RPO in India has been a fact that, as required by the legislative framework, the State Electricity Regulatory Agencies have been setting and enforcing RPOs within their jurisdiction. But the experience on setting RPOs has not been satisfactory to begin with. Most of the states have been setting RPO for a period of 3–5 years. But, in contrast, investors have been looking for specific

provisions in the law itself about the long-term trajectory of RPO. It is argued that only the legal mandate can bring in the desired level of demand with certainty. At the same time, the demand creation by itself is not sufficient. It needs to be backed up with strong enforcement of RPO. This would be the case, irrespective of whether the RPO is met through the administrative options on the table, the market mechanisms, such as the trade in RECs or, for that matter, the auctioning of development rights. Although strict enforcement has been missing in India, this aspect has been emphasized time and again at different fora. In fact, aggrieved by the apathy of the regulators, the wind associations have appealed before the Appellate Tribunal for Electricity for suitable directions to the state regulators to enforce RPO compliance.1

RE Tariffs Another concern has been around the plethora of RE tariffs across the states. Investors feel that the RE tariffs determined by the states do not always reflect the cost of generation. The FITs have been announced every year by the CERC (for central government-owned and interstate projects) as well as by SERCs (for state-specific projects), but there has been a wide diversity in tariffs determined by the CERC and SERCs. This has been the case since every state has been making its own assumptions on normative technical and financial parameters. This has led to different tariffs. The wind energy tariffs in states such as Gujarat, Andhra Pradesh and Karnataka have been lower than the CERC-determined wind tariff for FY 2014–2015, whereas they have been higher in states such as Rajasthan, Madhya Pradesh and Maharashtra. As a result, investors have been preferring investments in wind energy in these states.2 In Karnataka, the investor preference has been for captive and group captive mode for investments in RE from wind as the commercial and industrial consumers, who have been paying higher tariffs for electricity from conventional power stations,

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have found it far more cost-effective to set up captive wind generation facilities.3 This is, of course, inevitable and, to deal with this, the CERC spelt out a methodology to be used across India by SERCs to ensure consistency in the estimation of capital costs, which are a major constituent in the total cost of generation from these sources. However, this still is FIT, determined administratively, with all its drawbacks as an economic instrument for promoting investments in the RE power segment. Indeed, regulators and policymakers have since turned to approaches that offer market-like solution to pricing conundrum that has prevailed in pricing of electricity generated by RE power generators in India. The REC mechanism and the auctions are the two approaches that came into effect over the last decade for correcting the inadequacies in the FIT pricing. An advantage with a market mechanism like REC is that it separates the green feature of RE into a separate product (REC) which can be traded on a national exchange, whereas the electricity generated from these units can be traded on a par with that generated by conventional power generating units on national exchanges meant for trading in these units. This would eliminate the need for separate tariffs for green power in each state. Provided the market functions well, this should achieve the integration of green power into the national power system much more efficiently than instruments such as the FITs. Equally importantly, in aggregate, the market-determined price would correspond with the marginal cost of supplying electricity from RE sources, which is, as a matter of principle, a widely recommended approach worldwide for pricing electricity. However, in principle, the RE electricity price discovered through the auction process also corresponds to the marginal cost of supplying electricity over a long run from an RE resource. Lately, this approach has found greater favour with the government and the developers. The RECs were first introduced in 2010. However, there have been issues in promoting them. The initial euphoria that followed after their launch has ebbed over a period, leading to the

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Prices of Solar Projects Discovered through Table 10.1  Bidding Project

Year of Auction

Price

Solar

2017 (January–December)

In the range of `2.44–5.64 per kWh Weighted average `3.18 per kWh

2018 (January–December)

In the range of `2.44–3.55 per kWh Weighted average `2.89 per kWh

2019–2020 (January 2019–March 2020)

`2.48–3.25 per kWh Weighted average `2.74 per kWh

Source: http://cercind.gov.in/2020/orders/5-SM-2020.pdf

dampening of investment climate for registering projects under this scheme.4 Considering that the RPO enforcement has been very weak, obligated entities, especially the DISCOMs, have not been coming forward to purchase the RECs. While this has been a general situation, the government’s shift in the last few years to auctioning RE development rights to companies operating in this segment created a great deal of interest initially. The competitive bidding led to a significant fall in the number of FITs quoted in the winning bids, especially for solar (see Table 10.1 and Appendices 5B and 5C). But an inappropriate auction design has eventually led to a diminishing interest in bidders to bid in RE tenders. We assess here the two approaches discussed above. Principally, both conform to the pricing criterion, which is widely recommended for pricing electricity, as stated above. It may not be far-fetched to expect experienced RE power developers to factor in the risks associated with infirm power, such as wind and solar, in assessing their investments.

Assessment of Indian Auction Process Auctions have proved to be a transparent mechanism for allocating the development rights to wind and solar project Renewable Policy Introspection  201

developers in India. They are useful tools in discovering the price of electricity generated by RE power units. They overcome the practical difficulties which were discussed earlier in applying a marginal cost pricing approach to electricity generation for market consumption from solar and wind power farms.5 India follows the two-stage reverse bidding auctions for allotting development rights for solar and wind power development. The first stage, which is electronic sealed-price bidding, is conceptually equivalent to the conventional first-price bidding. It is used for shortlisting candidates for the second-stage bidding. The next stage in this approach is a more dynamic open-bid pricing. While both stages of this approach have led to what economists call ‘price discrimination’ (in that the buyer/auctioneer using his/her monopsonistic bargaining power extracts maximum benefit for himself/herself, leaving each winning bidder with just the bare minimum value to keep him/her interested in the project), the second bidding stage potentially has the effect of discouraging developers from participating in auctions. This has been borne out by the falling interest of RE power developers in bidding for RE auctions. There have been instances in the last one year when the tenders for the development of RE capacities have fallen through for want of interest. As explained earlier, with its policy of encouraging domestic wind and solar power equipment manufacturers to invest in equipment manufacturing capacities within the country, China has used auctions more often for revealing costs and establishing cost benchmarks for setting up economically efficient FITs. Moreover, unlike India, it has restricted itself to just the single-stage electronic closed-bid auctions. While it is tempting to recommend that India emulate the Chinese approach, considering its national goal too is to encourage domestic manufacturing of equipment within its territory, perhaps a more nuanced approach, using auctions, might be better suited to achieving its objective. In two-stage reverse Indian auctions, generally a small set of winning bidders is identified whose offered RE power capacities

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add up to an aggregate capacity announced in the tenders for development of RE generation capacity in an area in any particular year. The bidding prices of the winning bidders, at the end of the second stage of these auctions, define a band of the lowest prices that have made the grade. The PPA is signed by the concerned government agencies with each successful bidder in this band at its bid price. The higher most price in the band of winning bidders’ prices is, in fact, equivalent to the conventional market-clearing price of a marginal supplier of goods or services in any competitive market. Therefore, paying this price uniformly to all qualifying developers, in contrast to paying each of them their bid price, would be both non-discriminatory and efficient. It is thus a discovered price at which all the PPAs with the winning bidders should be signed, and not individually, as is the case now, at their quoted bid prices. Besides, as the experience suggests, the differences in bid prices in the first and second stages of the reverse bid auctions have not been significantly different to warrant an extra stage for fine-tuning them further. Also, the first-price sealed-bid auction, on which the first stage of the auction is based, is in principle both efficient and fair, when seen from a broader objective of encouraging investments in ‘Make in India’. Thus, it may be appropriate to drop the second stage of reverse bidding, which adds little value but discourages investments in the expansion of RE electricity generation.

REC Scheme It is about a decade since the GOI introduced the REC scheme. The said scheme became initially one of the two modes nationally—the other being FIT—by which obligated entities across the country could fulfil their annual purchase obligations through third-party wind and solar electricity producers. The said scheme was conceived as an effective marketable instrument to deliver national obligation targets annually, more efficiently than the prevailing FIT regime. But did it

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achieve the objective for which it was set up? Over the seven years spanning 2010–2017, 2,265.872 MW of new renewable generation capacities came up under the REC mechanism. This constituted only 6.75 per cent of the total RE capacity growth during that period. Initially, the scheme did evoke a positive response, but gradually the enthusiasm began to fade away. The number of projects registered under it began to decline and its efficacy as an instrument to deliver RPO compliance began to be doubted.6 After the government switched over to auctioning as an exclusive mode for identifying and registering developers for RPO-linked wind and solar power projects, the trading in RECs came to a virtual halt. Since then, its future has looked dim. Almost all through the scheme’s years in operation, a demand–supply mismatch prevailed between the projects registered under it and the purchases made by obligated entities. As a result, the wind and solar power generating units operating under this mechanism continued to accumulate unsold inventories of REC year after year. This situation could, of course, have been rectified by revoking the cap on floor prices of RECs. However, the cap was seen as an essential tool for mitigating the downside risk for RE electricity suppliers, and so was the ceiling price for protecting obligated entities against the risk of a runaway rise in REC prices. As one would expect, there indeed have been several explanations for the scheme’s inability in delivering nationwide RPO compliance by obligated entities like the power distribution agencies in India. One of the principal reasons cited has been the conflict between the FIT and the REC mechanisms, which predictably led to the decline of project registrations under the latter. Obligated entities, given a choice between the overall stable costs of meeting their RE obligations from units registered under the FIT regime and those registered under the REC mechanism, chose the former, implying that the latter’s more uncertain cost components (due to fluctuating REC prices) visa-vis the former made it more risky than the predetermined FITs and, hence, less attractive for obligated entities.

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That said, it has been common knowledge that the overall acceptance of the RPO targets by obligated entities has remained low over the years across Indian states. This has been principally on account of the reluctance by the governmentowned electricity distribution entities to honour their RPOs. However, one of the redeeming features of the REC-driven RPS has been that the trend in the acquisition of certificates was not entirely negative across all segments of obligated entities. In contrast to the public sector electricity DISCOMs, the REC scheme showed far greater promise with the openaccess captive buyers, the private sector DISCOMs and the electricity departments of the UTs.7 This implies that since the public sector DISCOMs constituted an overwhelmingly higher share of the total annual aggregate national renewable power purchases than all other segments of the RPO, the growth in smaller segments was not sufficient to upset the overall declining trend in the former. Could this apathy of state-owned DISCOMs be explained simply by psychological factors such as the REC not being accompanied by real power and hence of no tangible value? While it is difficult to conclusively prove this, logically, if this were so, it would mean that public sector entities lacked skills to assess risk, unlike those in the private sector. This of course would require an appropriate training programme in the risk assessment for personnel in these companies and for correcting their misconception. Nevertheless, it evidently appears that to make the REC scheme successful, the FIT scheme should have been withdrawn, especially since the full cost pricing is an inefficient approach to pricing a unit of electricity produced by generators in the renewable electricity generating sector. Against this background, one option could have been to emulate the UK approach, where the units of electricity were bundled in their tradable products and sold in the market as a single joint product to obligated entities by RE generators. However, if one recalls that the original purpose behind creating the REC mechanism in India, which was to facilitate obligated

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entities operating in RE-scarce resource states to secure their RPO without actually having to purchase electricity from renewable power generating units in RE resource-rich states, it is apparent that the bundling of tangible with the intangible product as in the case of the UK would not have served the purpose behind setting up of the REC mechanism. Although the idea behind launching of REC-backed RPS looked promising, there have been only a few well-endowed states with RE resources in India. This has major operational implication for operations of electricity grids in these states. The REC regime (as also the framework of interstate transfer of physical RE generation) has the effect of leaving these states carrying a disproportionate burden of investing in renewable power generating units, well beyond the requirements of obligated entities within them. Dealing with it would require additional investments in infrastructure. Thus, REC is not a costless option.

Variable Power Supply and Grid Stability The issue of load variability in India’s power system has been around since long before the grid-linked RE generation came into the commercial sphere. The original source of variability in power grids has been the uneven daily demand pattern in electricity grids of most states. The addition of RE generation to states’ grids adds to this uncertainty from the supply side. Generally, the volatility due to demand fluctuations can be managed by conventional measures on the supply side, such as providing quick ramping-up power capacities like hydropower and, to some extent, gas-based power stations. Similarly, it can be managed by demand clipping during peak periods with demand-side management measures on the consumer side. Much of this has been known and enough has been written about it. There are some SEBs in India that have already taken steps to level daily loads, but many others have not. However, as things

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stand, this volatility has been managed with power stations having rapid ramping capabilities or simply by load shedding, which is the worst of all the options that any distribution utility can exercise. In contrast to demand-side volatility, the volatility induced in the system by intermittent RE power is governed by natural factors; it is stochastic and often variable across seasons and regions. For that reason, it is more difficult to manage with the soft options designed for influencing consumer response. It requires appropriate infrastructural hardware to manage it. Load forecasting at short intervals is one of the most important solutions to deal with it. Although quick response from hydropower and other ramping power stations can generally provide relief against volatility in the system, the unit cost of electricity generated from such stations is high, as these units, unlike conventional power stations, are operated only during limited time slots when system volatility is high. This has the effect of spreading the overhead costs over fewer electrical units generated for the purpose by these power stations, pushing up the electricity rates steeply. Although pumped hydropower has been established as a proven storage technology to handle this situation, its deployment has remained limited in India due to reasons such as competing uses of water, for example, in irrigation. More worryingly, there has been little incentive to build storage since the time of the day supply is not priced to reflect its scarcity value during different times of the day. But the naturally determined, unsteady stochastic patters of renewable power generation during a day can be a major constraint on using even the time of the day pricing. This requires investments in standby ramping facilities over and above those installed for dealing with fluctuations in demand from the consumer side. But looking at total hydro capacity in India, which as of now is close to 50 GW, only 16 GW

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of this has been linked with the ISTS.8 This is a major constraint. However, the gas-based conventional ramping power station can also play a useful role in dealing with the problem, but this, too, is costly. Yet for achieving accelerated RE growth in the years to come, it is imperative that these and reasonably priced storage technologies are developed for implementing retail time of the day electricity pricing (preferably in 5-minute slots for greater accuracy in forecasting). If one considers the current state of the power sector in India, this will take many years to roll out. News reports suggest that as a percentage of India’s total power capacity, by 2030,9 RE power generation would constitute half of it. To address this situation, investments in related infrastructure will have to be jacked up significantly than they are at present. The number of smart meters installed in India is grossly inadequate. Only about 250 million meters have been installed in the country so far. Indigenous manufacturing capability, on the other hand, has been just about 25 million meters per year. At this rate, it would take at least a decade, including communications infrastructure, to replace outdated meters. To accelerate these installations, the government will have to liberalize imports of smart meters while, at the same time, accelerating their manufacture here. Also, the interface boundaries between entities have still not been well defined. It too would require prompt action. At the same time, a robust, scalable, dispute-free settlement mechanism, which only a couple of states have at present, will have to be set up in all states that are lagging behind. Further, the state-level forecasting and scheduling framework will have to be put in place across all states. The skill set of those responsible for operating this will have to be jacked up with appropriate training. All this and much more will have to be done if India is to achieve its ambitious goal of expanding the presence of grid-linked wind and solar capacities in its power system. The beginning would have to be made soon to address these inadequacies.

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REC versus Auctions Given this situation, what is the way forward? While both REC and auctions are appropriate pricing tools, should the former be given preference and the REC scheme revived or should the auctioning system for allotting RE power development rights be given primacy? If one contrasts REC with the auction approach, obligated entities in the latter have to actually purchase their renewable power requirements from the RE power projects that have made the grade at the end of the auction. Entities in states with scarce RE resources have to wheel electricity from RE units in high RE-resource states, through interstate transmission networks, to their destination to meet their RPO. In normal course, they would have to pay interstate transmission charges for wheeling electricity. Fortunately, for them, they are exempted from having to pay the wheeling charge. Nonetheless, someone has to foot the bill, which in India the rate payer does. Further, comparing investments required in infrastructure for maintaining grid stability in RE resource-rich states between the two schemes, it would be larger under the REC than in the auctioning approach. This is because the power produced from additional RE power capacities installed in the latter case for serving obligated entities in other states is actually transferred out of the parent grids to the grids in which obligated entities are located; to that extent, the units selected through the auctioning process operate in an extended grid that is larger than the parent grid. Thus, the parent grid is, to that extent, in the case of an auction mechanism, less constrained by instability issues than under the REC approach. Hence, investments required for maintaining the parent grid stability are less with the auction approach than with the REC mechanism. Thus, the choice between the REC and the auctions boils down to a tradeoff between the cost of additional investments in infrastructure required for maintaining grid stability in the former and the costs of wheeling the power in the latter. However, the electricity price discovered through the auction mechanism imparts far greater certainty to the revenue

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projections of RE power developers than the gross electricity price (the actual electricity price plus the market-determined REC price) discovered under the REC mechanism. To that extent, RE capacity auctions, provided they are properly structured, are a better option in securing the required RE capacity additions on the ground than the REC mechanism. However, despite its inherent advantages over the REC mechanism, the auctions have showed signs of faltering recently. This is primarily due to a faulty design that requires correction.

Deficient Infrastructure Looking beyond issues in pricing, markets must have the essential infrastructure to function smoothly. In this respect, much needs to be done to integrate intermittent RE generation into the grid. Indeed, there is a dire need to upgrade state, regional and national grid technology and operational procedures in India. In conjunction with technology and operational upgrades, there is also a need for a regulatory framework for procuring and reasonably compensating ancillary and balancing resources. These aspects, and those associated with the grid integration of variable generation, pose the biggest challenge. However, the main reason behind the lukewarm response of the state government-owned power DISCOMs to the RPO has been their poor financial health. Estimates show that the total accumulated losses of these distribution licensees were about `3,800,000 million in FY 2015,10 though not all of it is accounted by the purchase of electricity from wind and solar power farms. This is a much bigger issue affecting the entire power sector since many years and needs urgent solution at the government level. The developers have been also concerned with the overall environment for RE project development. They have often complained about the lack of coordination among key institutions, namely grid operators, DISCOMs, state revenue departments

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and environmental agencies. This is a principal cause of time and cost overruns in project execution. While this needs correction, more specifically the main cause for high transaction costs is the lack of coordination in land acquisition, transmission interconnections and environmental clearances.11 In so far as the land acquisition is concerned, a country as vast as India would require socially and politically sustainable land acquisition policies that are seen to be fair by all stakeholders. Further, the sites for RE power development will have to be a priori identified and assessed for environmental clearance by the state governments themselves before offering them for development.

What Is to Be Done: Suggested Way Forward To round up, over a period, countries across geographies have extended support in the form of fiscal and financial incentives (PTC, capital subsidy, etc.) and policy/regulatory support in the form of FITs and the RPS. In countries where FIT as a policy and regulatory instrument has been adopted, renewable capacity addition has taken place through a supply-side push. The basic premise of FIT support has been that there is guaranteed grid access or must-run status (‘feed-in’ component of FIT) and assured tariff (‘tariff’ element of FIT) for a longer duration. In countries where RPS has been adopted as a policy intervention, tariff support in the form of FIT is generally not considered necessary. RPS has been conceived as a market instrument with two components, namely RPO and RO/REC. In India, the initiatives include national policy frameworks (National Solar Mission, RPO under the EA, the proposed National Wind Mission, etc.), financial incentives (accelerated depreciation, generation-based incentives, FIT, capital subsidies, etc.) and other support mechanisms (e.g., grid codes, scheduling/ dispatch, etc.). As regards policy/regulatory support of FIT and RPS, India has experimented with both the FIT mechanism and an Indian version of RPS. Thus, obligated entities in India have

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the obligation to meet RPO and they can use FIT or REC, or both as instrument(s) for RPO compliance. India started with FIT under an administered mode but has been gradually moving towards auction mode, especially for wind and solar. In this respect, the experience of over a decade has shown that multiple approaches for developing RE power segment, which are in use at present, are not appropriate. They must be done away with, and only the most efficient of them must be retained. From the point of view of larger sectoral efficiency, both REC and, wind and solar auctioning approaches meet the criterion, but the latter is more advantageous than the REC in that it ensures investments upfront in the targeted annual RE capacity in each state, rather than depending entirely on developers to individually come forth with the requisite investment proposals that cumulatively add up to the targeted annual RE capacities in states. Thus, the auctioning approach must be continued, but the existing auction design must be modified to include only the first stage, with the ‘first-price electronically sealed bidding’ retained for its design. Next, with the REC being discarded, the legacy units that have come up under it will have to be appropriately repositioned. Transferring them under the existing FIT regime in each state with the same electricity tariff as that prevailing for the units of similar vintage must be considered promptly to avoid any uncertainty on this score. While the overall cost of renewable has been declining because of competition, a question that still haunts is on the balancing cost of integrating renewable. There are studies12 which have estimated the additional balancing cost to the tune of `1.11/ kWh for all-India scenario for 2022. This includes the following components, namely (a) `0.04/kWh towards fixed plus fuel cost of coal- and gas-based generating stations; (b) `0.30/kWh towards additional impact of deviation charges; (c) `0/kWh in terms of impact in tariff because of backing down coal generation (assumption: solar and wind price of `2.50/kWh and coal 212  Renewable Energy in India

generation price of `3.50/kWh); (d) `0.50/kWh as a standby charge and (e) `0.26/kWh towards additional transmission charge. All of these computations have been done by spreading additional costs over renewable generation. Let’s examine as to whether these numbers can be taken on their face value or not. The first issue in the above exercise seems to be of double counting of some impacts. For instance, if additional gas-based generation and standby charges are factored in for supporting variability of RE, the impact on account of additional deviation charge to the tune of `0.30/kWh seems to be exaggerated. Second, the impact on account of backing down coal should not have been taken as zero; rather, the negative value should have been considered for the purpose of the impact assessment in view of the fact that low-cost wind/ solar (`2.50/kWh) was assumed to be replacing high-cost coal generation (`3.50/kWh). Most importantly, the impact has been assessed by spreading the additional cost over renewable generation, which, in our opinion, is not correct. Rather, it should be spread over the entire generation, in which case the impact would be significantly less than `1.11/kWh. In this context, it is important to note that there is definitely going to be an additional cost for integrating renewable into a power system (for instance, as a result of lower capacity utilization of thermal assets, costs towards reserves, etc.) but not as high as projected in the above report. The phenomenon is global in nature; however, when spread over the entire generation in the country, its impact does not appear that alarming. Another important point is that while carrying out such estimation, one thing which is often lost sight of is the environmental impact and the associated cost on account of environmental degradation if one were to continue with fossil fuel in the future. The external environmental cost on account of continued use of fossil fuel, if monetized, could outweigh the balancing cost for renewable. In addition, the declining energy cost of renewable when compared with the ever-increasing price of fossil fuel makes a strong case for renewable. The levelized

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cost of renewable, as is being discovered through the bidding process, currently is going to remain constant through the next 25 years, whereas the cost of fossil fuel generation, even though it is less than the renewable cost as at present, is poised to increase substantially in the future. Another important point to note is that the balancing cost looks high when estimated only with reference to load and generation portfolio of a state in isolation. This reinforces the need for a larger scheduling and balancing area and market. As already emphasized earlier, the balancing cost as also RE curtailment can drastically reduce if balancing area and market size increase.13 Load pattern varies from state to state. Complementariness of load between states and regions can be harnessed through a larger market. This in turn can lead to an optimal utilization of generation assets, and what is counted as stranded in the estimation of balancing cost in respect of one state might no longer remain stranded in the larger market. The UI charge, which is also counted as balancing cost, might reduce substantially with suitable market reforms, for instance, if aggregation of variable RE is allowed and closer to RTM is institutionalized. Given this discussion, what is the right way forward for India in terms of promotion of renewable? We have already discussed the need for suitable market design tweaks for integrating renewable. It is reiterated that a centralized market with a large number of buyers and sellers is more suitable for addressing the variability of renewable. As such, the way forward lies in continuing with the procurement of RE in the future based on the auction route. However, apart from the modification in the auction design discussed above, another transformation suggested is in terms of mandating them to participate in the day-ahead market and RTM. The mechanism on the lines of the CFD should be adopted for future RE capacity addition, whereby the difference between the energy price as earned by these generators in the market and the strike/contract price should be settled by the procurer.

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The SECI could invite bids for central procurement. The tariff discovered should be treated as a reference/strike price for the purpose of CFD. On a day-ahead basis, the selected developer could be asked to go to PX and sell its power like any other conventional generator. If the price received by the RE generator from the market is higher than the reference/strike price, the gain over and above the reference/strike price could be refunded by such generator to the SECI. On the other hand, if the price received by the RE generator from the market is lower than the reference/strike price, the loss vis-a-vis the reference/strike price could be compensated to such generator by the SECI. The final adjustment can be done on a monthly/annual basis. Given the price trends in PX and the prices discovered for wind/solar, it is felt that the SECI should not be in deficit. However, in the event of shortfall, the same can be considered for socialization. The incremental impact of such socialization should in our estimation be less than or comparable to that arising from the current practice of waiver of transmission charges and losses (see Box 10.1). In fact, for the capacity contracted through this route, there should not be any requirement of waiver of transmission charges and losses. CFD support could be given initially for a predefined target capacity of renewable. Eventually, as renewable becomes more and more firm with improved forecasting and combined with energy storage, the balancing cost would also decline, and they would then be able to compete with conventional generators based on ‘firm capacity’. It is at this stage that explicit support would no longer be required for RE. For the existing projects as well, the CFD mechanism can be tried. The option of CFD could be given to RE generators by the DISCOMs that have already entered into PPAs with such generators. The role as envisaged for the SECI (in the preceding section) needs to be played by DISCOMs. The other option is for the DISCOMs to act as a portfolio player and to manage the RE contracts along with their variability through day-ahead market or RTM.

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Box 10.1 CFD Socialization versus Waiver of Transmission Charges and Losses Currently, in India, there is a policy of waiver of interstate transmission charges and losses for 25 years for wind and solar generators commissioned up to 30 June 2023.14 Let us look at the impact of such a waiver in terms of tariff. Annual interstate transmission charges for 2019–2020 are reported to be in the range of `392,850 million.15 Further, the total annual generation in the country for the same period has been approximately 1,391 BU.16 From this, if we exclude generation from intrastate generating stations, say the equivalent of approximately 50 per cent of the total generation, we are left with 700 BU (approximately 50% of the total generation of 1,391 BU) which can be attributed to interstate generation by using interstate transmission. Dividing the interstate transmission charges of `392,850 million by interstate generation of 700 BU, we get approximately 56.12 paise per unit (`392,850 million/700 BU) as the interstate transmission charge. To this, if we account for the average of interstate transmission loss of 3 per cent, the effective interstate transmission charge works out to be approximately 57.85 paise per unit (56.12/0.97). Now, we estimate the renewable energy qualifying for waiver of interstate transmission charges and losses. We find that approximately 8 per cent of the total generation in the country is contributed by wind and solar. If transmission charges and losses were to be waived for generation from interstate wind and solar generators (waiver is applicable to such projects; in this case, assuming 50% of 8%, i.e., 4% is the contribution from generators eligible for waiver), this would mean the same amount of `392,850 million is to be recovered from 672 BU (700 BU – 28 BU being approximately 4% of 700 BU), resulting in interstate transmission charge of 58.46 paise per unit (`392,850 million/672 BU). Accounting for average interstate transmission loss of 3 per cent, the effective interstate transmission charge works out to be approximately 60.27 paise per unit. Therefore, the incremental impact of the waiver of transmission charges and losses could be stated to be approximately 2.42 paise per unit (60.27 – 57.85). Depending on the assumptions above, the impact would vary between 2 paise and 3 paise per unit.

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Now, we compare this against the likely cost of socialization of the CFD mechanism. We observe that the weighted average market clearing price of the day-ahead market segment of the PX has been in the range of about `3.16 per unit during 2019–2020.17 As against this, the weighted average price of solar power discovered through auction during the same period has been in the range of about `2.74 per unit (Refer to Table 10.1). There could be an increase in the price of solar in the future due to the incidence of taxation or insistence on a policy of domestic content. The increase is also likely if we expect the solar generator to account for the deviation/forecasting error-related cost. As against this, we also assume a reduction in the PX-discovered day-ahead market-clearing price as a result of increasing participation of zero marginal cost renewable generation in the day-ahead market. One could, therefore, argue that the gap between the current level of market-clearing price of `3.16 per unit and the auction price of solar of `2.74 per unit would eventually narrow down and become zero or negative. However, in our opinion, the gap being 42 paise (`3.16 – `2.74) per unit is too large to be eliminated in the short run. However, even in the extreme event of the price of solar power exceeding the market clearing price of the PX, the impact of the socialization of such cost would be much less than that on account of waiver of interstate transmission charges and losses. For instance, if the solar price exceeds the market-clearing price by, say, 10 paise per unit, the cost towards the same level of RE generation, that is, 28 BU, would work out to `280 million (28 BU × 0.10), which, if socialized over 700 BU, would have an impact in the range of 0.0004 paise per unit, which is way less than 2 to 3 paise per unit in the case of waiver of inter-transmission charges and losses. Further, the cost of socialization, if any under the CFD mechanism, could be negative or positive depending on the marketclearing price and, as such, the impact is not perennial in nature, unlike in the case of a waiver of interstate transmission charges which is fixed for 25 years for any eligible project. In view of the above, we recommend the CFD mechanism as a future instrument for RE capacity addition at least for a predefined target capacity. Alongside, the policy of waiver of interstate transmission charges and losses should be dispensed with. As against the waiver, the net excess liability of the procurer under the CFD mechanism, if any, should be socialized.

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RTM is the ideal platform for the integration of variable RE sources. The half-hourly market is close enough to the actual time of delivery and gives adequate flexibility to RE generators to forecast accurately. Centralized economic dispatch in the day-ahead and real-time horizon helps full dispatch of RE being zero marginal cost generation. The revenue earning potential for such generators arises from the difference between the market-clearing price and their actual cost of generation. The existence of RTM after the day-ahead market gives RE generators an opportunity to correct their position closer to the actual time of operation. RE is likely to be firmer going forward with advanced forecasting and in combination with energy storage, given the fast-declining price of battery storage technologies. As such, a centralized RTM is the way forward for mainstreaming RE sources, without the need for any special concession like waiver of transmission charges and losses, etc. Once a framework like this is adopted, there would not be the requirement for RPO for the capacity contracted through this mechanism. There would not be any need for demand-side support by way of RPO, as renewable capacity would be added based on the assurance of contract price. Finally, going beyond pricing concerns, efforts will have to be made to resolve several related issues in order to facilitate the competitiveness of RE technologies. Thus, efforts will have to be made towards reducing the costs of financing RE technologies. Currently, the cost of financing energy projects, conventional and renewable power projects, ranges between 12 per cent and 14 per cent in India. Debt constitutes about 70–80 per cent of total project costs. In this respect, RE projects are on par with conventional power projects. But the costs of solar and wind per unit generation are proportionately more capital dependent on MW to MW comparisons with conventional power projects. Since the ultimate aim is to encourage third-party investments, a time-bound interest subsidy scheme could be considered by the government for these projects. The other option would be to consider bringing RE under the priority sector lending, allowing pension funds and insurance 218  Renewable Energy in India

companies to invest in RE projects and securitizing these loans into trading instruments to be traded in capital markets. This would allow longer tenure loans to flow without unduly hampering liquidity. Yet one more option could be to consider the infrastructure debt fund for investments in these units.18 Lastly, the debate around centralized forecasting and scheduling at the state level has been going on for quite some time. The Green Energy Corridor Report19 has provided for a framework in this context. It has recommended the setting up of the REMC for the purpose of centralized forecasting and scheduling. There is merit to these recommendations and their implementation must be undertaken in all earnest. It is understood that there has been some progress towards the establishment of the REMC in three regions (southern region, northern region and western region) involving seven states. The automation of forecasting and scheduling and real-time tracking of RE generation—the two key expectations of the REMC—are critical to the successful integration of variable RE in the country. Another important intervention that demands attention is the aggregation of RE projects for the purpose of forecasting and scheduling. Aggregation could happen at the level of the pooling station. The FOR has recommended the concept of a Qualified Coordinating Agency (QCA) for aggregating wind or solar projects at a pooling station. The QCAs are supposed to be responsible for collating the likely generation data of all RE projects at the pooling station and coordinating with the system operator for combined forecasting and scheduling. The premise is that the larger the scheduling area, the less the probability of forecasting error. This is definitely a welcome step. The need is for the regulators to recognize the entity in their regulations. There are demands in states like Tamil Nadu to allow pooling of pooling stations. In Karnataka, the regulator has allowed such an arrangement. While there are clear benefits of aggregation, the demands of generators for freedom of choice to be on their own need be honoured. Given the intermittent nature of RE, the establishment of the REMC and the institutionalization of Renewable Policy Introspection  219

the QCA will take a long time in bringing the desired firmness in such variable generation. This is desirable from the point of view of secure grid operation and shall also help to reduce the burden of the deviation penalty on renewable generators. These aspects need to be taken forward at right earnest in the interest of the power system operation in general and for the mainstreaming of renewable in particular. We believe that the two interventions, namely aggregation/QCA and REMC, put together will address the concerns regarding the forecasting error and the consequent financial impact on the project developers while, at the same time, addressing the concerns of the system operator in terms of balancing the grid operation. As more variable RE generation comes online, the day-ahead forecasting errors in net load can be expected to increase; and, with that, the need for intraday market and/or AS to provide load following reserves too would increase. The CERC has floated a concept note on introducing a framework of marketbased procurement of AS. This must be undertaken soon rather than waiting for the situation to develop in the near future and then to firefight. Since power cannot be supplied cost-effectively to many remote areas of the country, it might be useful to consider and promote alternatives such as providing stand-alone off-grid systems in remote rural areas for home lighting and running other basic appliances. As of now, in some states, private entrepreneurs have successfully launched marketing packages for small-sized solar panels. However, since village electrification with the grids in India is 100 per cent complete, it is a major threat to these initiatives as the government pursues 100 per cent household electrification policy. As of now, household acceptance of distributed technologies is driven by the lack of guaranteed supply of electricity from the grid, but this could change rapidly as the electricity supply from the grid improves. The government will have to evaluate which of the two options is economically preferable and evolve its policy accordingly in this respect.

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Chapter Conclusion Given the target of RE capacity addition of 175 GW by 2022 and 275 GW by 2027, there is an urgent need for a course correction on policy space for India. We believe that, to start with, the RPO regime needs to be revisited. There is already a wide divergence in vision between the centre and the states on this issue—the centre talks about the commitment of the INDC and looks at energy security and climate change issue with pan-India scenario in mind, and the states are wary about the commercial and operational impact of ambitious renewable and consequently RPO targets. In a federal polity like in India, there is a limit beyond which one side cannot coax the other and, in fact, such differences only give rise to avoidable confusion for investment in the sector. As such, there is a need for evolving an alternative to the RPO mechanism for the promotion of renewable. Our recommendation, therefore, is that ideally explicit support in the form of RPO should be reviewed by freezing the current level of RPO percentage without insisting on increasing the RPO percentage in the future. RPO is generally set as a percentage of consumption in a state and consumption continues to increase. As such, even if we freeze the current level of RPO percentage, in our opinion, it would support not only the existing contracted RE capacity of, say, 90 GW but also some additional capacity as consumption increases over the period. The question as to what should be the ‘current level’ of the RPO percentage for each state before it is frozen should be evolved as a consensus by the FOR. Interestingly, the FOR had earlier done an exercise20 on this with financial and operational impact in mind. That exercise should be updated and refined with current realities. In the future, an alternative mechanism of fixed tariff support, with a focus on the scheme of CFD should be introduced, but such CFD support should also be limited to prespecified target capacity. For the capacity contracted through this route, there would not be any need for RPO. Even the must-run

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status—which is not a guarantee in the RPO regime as well— might not be required for such a contracted capacity as their zero or low SRMC of generation would guarantee their dispatch in the market. Another departure from the business-as-usual policy that we recommend is to dispense with the policy of waiver of interstate transmission charges and losses. Also, the special dispensation on deviation for wind and solar should be phased out gradually as we believe that market mechanism will provide natural support for managing deviation. Thus, going forward, efforts should be concentrated on market reforms in the form of enhancing forecasting capabilities, operationalizing REMCs, enlarging scheduling and balancing areas through aggregation of wind and solar at pooling station level or by pooling of pooling stations. At the same time, the transmission pricing mechanism should be modified to articulate clearly that transmission charges would be borne by DISCOMs/buyers explicitly without the need for allocating any transmission charge on generators, including RE generators. With the utmost urgency, the market geographies need to be enlarged and the depth of the market on day-ahead and real-time horizons need to be increased through MBED. The market clearing needs to be quicker by gradually moving from a 15-minute slot to a 5-minute slot for RE and load to manage their variation without leaning on the grid through UI and causing the avoidable risk to grid operation. These market reforms, together with the pooling of wind and solar at least at the pooling station level, would go a long way in reducing the balancing cost for renewable. Equally important is the need for facilitating adequate reserves and to creating a framework for a market-based procurement of AS with proper incentives for higher ramps. Even these measures have a cost for the rate payers (electricity consumers), but these costs are going to be much lesser than that being borne by individual states currently operating as they are in their silos. The other advantage is that the mechanisms suggested will eventually make the variable renewable compete with conventional generation, which in turn would reduce the DISCOMs’ resistance that we believe is currently 222  Renewable Energy in India

one of the biggest factors contributing to the dampening of interest of investors in the RE segment. An increase in the penetration of renewable is definitely going to render some of the conventional power plants stranded. Options to mitigate risks for such legacy contracts be explored and, more importantly, the resource adequacy requirement and the future power procurement strategy be redesigned with these realities in mind. There is thus a need for a paradigm shift in the strategy for the promotion of RE in India. What needs wider recognition is that RE generation technologies are here to stay with us given the worldwide context of global emissions concerns and limitations on the exploitation of fossil fuel resources. Much of the learning process is now over and it is therefore imperative that these technologies are promoted systematically going forward. Since these technologies are seen to be evolving approximately on Moore’s Law pattern—as in the case of information technology hardware—a regulatory approach will have to keep pace with the changes taking place in this and allied field to facilitate their smooth transition from one stage to the other.

Notes 1. http://reconnectenergy.com/blog/tag/iwtma/ (accessed on 29 September 2020). 2. http://www.nrdc.org/international/india/files/renewable-energywind-financing-IP.pdf (accessed on 29 September 2020). 3. http://cercind.gov.in/2014/draft_reg/Exp_memo30.pdf (accessed on 29 September 2020). 4. http://climatepolicyinitiative.org/wp-content/uploads/2012/12/ Falling-Short-An-Evaluation-of-the-Indian-Renewable-CertificateMarket.pdf (accessed on 29 September 2020). 5. Ralph Turvey, ‘Analysing the Marginal Cost of Water Supply’, Land Economics 52, no. 2 (1976; quoted in NERA Economic Consulting, ‘Assessment of IPART’s Estimate of Long Run Marginal Cost for Sydney Water’ [A report for Alinta LGA Ltd; White Plains, NY: NERA Economic Consulting, 2008]). 6. Chatterjee, ‘The Renewable Energy Policy Dilemma in India’. 7. Ibid.

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8. Forum of Regulators, ‘First Report of FOR Technical Committee on Implementation of Framework for Renewables at the State Level’. 9. Bloomberg report in Business Line, 3 July 2019. 10. https://powermin.nic.in/pdf/Power_Sector_Reforms.pdf (accessed on 1 May 2020). 11. http://awsassets.panda.org/downloads/meeting_renewable_ energy_targets__low_res_.pdf (accessed on 29 September 2020). 12. https://www.cea.nic.in/reports/others/planning/resd/resd_comm_ reports/report.pdf (accessed on 12 February 2021), 13–18. 13. https://posoco.in/wp-content/uploads/2017/06/National-StudyFull-report.pdf (accessed on 12 February 2021), 86, 138. 14. https://www.powermin.nic.in/sites/default/files/webform/notices/ Letter_dtd_5Aug_2020_reg_Waiver_of_ISTS_charges_and_losses. pdf (accessed on 15 February 2021). 15. http://cercind.gov.in/2020/market_monitoring/Annual%20Report %202019-20.pdf (accessed on 15 February 2021), 8. 16. Ibid., xiii. 17. Ibid., xvi. 18. http://www.nrdc.org/international/india/files/renewable-energysolar-financing-report.pdf (accessed on 29 September 2020), 119. 19. http://www.forumofregulators.gov.in/Data/study/Report-GreenEnergy-Tr.-corridor.pdf (accessed on 29 September 2020). 20. http://www.forumofregulators.gov.in/Data/Reports/Final_Report_ FOR_RPO_Study.pdf (accessed on 12 February 2021).

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About the Authors

Pramod Deo, former Chairman of the Central Electricity Regulatory Commission (CERC), was electricity regulator for over 11 years both at the centre and Maharashtra state. Now he is active as an independent energy and environment adviser. Deo has 35 years of experience in the energy sector at policy, regulatory and project management domains at both domestic—state and central government—and international levels. He was senior energy economist with the UNEP Risoe Centre on Energy, Climate and Sustainable Development, Denmark. Deo is a recipient of the World Wind Energy Award 2005 from the World Wind Energy Association for his outstanding achievement in the dissemination of wind energy. Rich in academics with a postgraduate degree in Physics, PhD in Infrastructure Economics and postdoctoral research in Energy Policy and Economics, he has co-authored three books on energy planning, energy management and regulatory approach to green power.

Sushanta K. Chatterjee is presently Chief (Regulatory Affairs) with the CERC. He has a long experience of dealing with power sector reforms, especially Regulatory Reforms, since its inception in 1998. He was actively involved in the formulation of the Electricity Act, 2003. Chatterjee has been a postdoctoral research fellow at the Harvard Kennedy School, USA. He has a PhD in Management and an MBA in Finance. He co-authored Electricity Sector in India: Policy and Regulation (Oxford University Press, 2012) and authored S. K. Chatterjee’s Commentary on the Electricity Laws of India (Delhi Law House, 2006). He has published papers on renewable/REC (World Bank 2013 and NREL 2016). He completed research work as Principal Investigator on the topic ‘Meeting the Renewable Revolution: A Roadmap for Electricity Market Design in India’ at the International Growth Centre, London School of Economics, UK (2017). Chatterjee has recently been elected as the first President of the India Chapter of the International Association of Energy Economics. Chatterjee’s present academic and professional pursuits involve specialization in public policy and regulation with a focus on renewable and market design. He has been instrumental in the conceptualization of the CERC staff discussion papers on real-time market, day-ahead market design, ancillary services framework, grid integration of renewable and renewable energy certificate mechanism. He is/has been a member of various government committees. He is/has been a guest faculty for various academic, research and training institutions such as Power Management Institute (PMI), National Power Training Institute (NPTI), Indian Institute of Management Ahmedabad, Indian Institute of Technology Kanpur, University of Petroleum and Energy Studies (UPES), Indian Institute of Technology Roorkee, The Energy and Resources Institute, Massachusetts Institute of Technology (USA), London School of Economics (UK) and Florence School of Regulation.

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Shrikant Modak has been a senior financial journalist with 30 years of experience in senior editorial positions in the country’s leading financial newspaper and magazines. His early career was in academics, where he was on the faculty of the Institute of Rural Management, Jamnalal Bajaj Institute of Management Studies (JBIMS), Mumbai University and Indira Gandhi Institute of Development Research. He has over 30 years of consulting experience in the field of energy economics and has written extensively on the subject in news media and academic journals. He has co-authored five books of which four have been in the field of energy economics. He holds a master’s degree in Economics from the London School of Economics.

About the Authors  227

Index

AC micro-grids, 48 ancillary services (AS) providers, 164 Andhra Pradesh Electricity Regulatory Commission (APERC), 32 ascending bid auctions, 69 auction theory (competitive bidding) Chinese approach, 77–78 e-reverse auction (eRA), 74–77 in India, 72–74 revenue equivalence theorem, 72 types of, 68–70 value structure of participating bidders, 71 automatic generation control (AGC) mechanism, 161, 165 average power purchase cost (APPC), 54, 140 Bayes–Nash equilibrium, 77 bilateral generation contracts, 23

carbon trading, 25 Central Electricity Authority National Electricity Plan, 112 Central Electricity Generating Board, England, 9 Central Electricity Regulatory Commission (CERC), 4, 37, 40, 62, 79 Central Electricity Regulatory Commission (Terms and Conditions for Recognition and Issuance of Renewable Energy Certificate for Renewable Energy Generation) Regulation, 2010, 139–142 clean development mechanisms (CDMs), 25 competitive markets, 19–21 connection agreement, 52 contract for difference (CFD), 192 Copenhagen Climate Summit, 111

DC grid, 48 decentralized generation, 43 Delhi Electricity Board, 22 demand for power in India, peak load, 1, 2 descending bid auctions, 69 Deviation Settlement Mechanism (DSM), 162–163 distributed energy resources, 43, 55 distribution companies (DISCOMs), 49, 51, 54, 56 distribution transformers (DTs), 52–53 Draft Electricity Bill, 4 dynamic minimum renewable purchase standard (DMRPS), 111 Edison, Thomas Alva, 6 Electricity Act, 2003 (EA, 2003), 4–6, 9, 12–13, 21–22, 32–34 Electricity Act of 1902,. Sweden, 9 Electricity Act of 1983, Britain, 9 electricity legislation in India, evolution of, 8–9 Electricity Regulatory Commissions Act, 1998, 9–10 electricity sector in India competitive bidding route, introduction of, 15–16 unbundling with renewable energy technologies, 25–26 electricity sector, technological and structural evolution, 6–8 Electricity (Supply) Act, 1948, 8–9, 33

Energy Act (1990), Norway, 9 Energy Conservation Act, 2001, 34 energy entrepreneurs (EE), 49 Federal Energy Regulatory Commission (FERC), USA, 30 feed in tariff (FIT) approach, 77 feed-in tariff (FIT) approach, 154, 211 first-price sealed-bid auctions, 69 fixed tariff regime, 155 Forum of Regulators (FOR), 51, 111, 122 grid angle, 24 grid-connected photovoltaic rooftop solar power generation system, 50–55 grid-connected rooftop system, 43 high-voltage direct current lines, 7 independent power producers (IPPs), 10 independent system operator (ISO), 17, 178 Indian Electricity Act, 1910, 8 Indian Electricity Grid Code (IEGC), 170 Indian Energy Exchange (IEX), 162 Indian Meteorological Department, 75 Intended Nationally Determined Contributions (INDC), India, 112 intermittent generation of renewable energy, 157–161 Index  229

Inter State Generating Station (ISGS), 162, 164 Inter-State Transmission System (ISTS), 162 intrastate generators, 162 intrastate transmission and distribution, 23 locational marginal price (LMP), 178 long-run marginal cost (LRMC), 20, 35 marginal cost pricing, 106 Market Based Economic Dispatch (MBED), 189, 194 market design for renewable energy Indian model, 182–189 issues in, 177–178 market models in major economies, 178–182 recommended design for Indian markets, 189–194 market mechanism, 106–107 Mera Gao Power (MGP), 48 meter energy storage, 43 micro-DISCOMS, 49 micro-grid, 43, 47–50 Minda, 49 mini-grid, 43 Ministry of New and Renewable Energy (MNRE), 3, 32, 51, 73 Ministry of Urban Development Model Building Bye-Laws, 2016, 112 Model Net Metering Regulation (NEM 2013), 51 M-Pesa platform, 45

230  Renewable Energy in India

National Action Plan for Climate Change (NAPCC), 111–112 National Electricity Market, 9 National Electricity Policy, 164 National Institute of Solar Energy, 50 National Institute of Wind Energy, 75 National Load Dispatch Centre (NLDC), 162 National Renewable Energy Laboratory, 75 National Solar Mission (2011), 113 network service-based energy storage, 43 New Electricity Trading Arrangement (NETA), 18–19 Non-Fossil Fuel Obligation (NFFO), Britain, 29, 109 Nord Pool market of Scandinavia, 19 North American Electric Reliability Corporation, 171 off-grid/small home system, 44–47 Orissa Electricity Board, 22 parallel power modelling technique, 38 pay-as-you-go (PAYG), East Africa, 44–45 peer-to-peer (P2P) trading, 55–57 pooling system for power trading model, 16–19 power generation technology, advancement in, 8 Power Grid Corporation of India, 149

Power Grid Corporation of India Limited, 74 power industry in England and Wales, activities of, 17 power purchase agreement (PPA), 51, 54, 68, 166 power sector, global reforms in, 9 power system operation in India imbalance handling, 163–165 scheduling and dispatch, 161–163 power tariff, 12–13 pricing of renewable energy, approaches, 61 Public Utility Regulatory Policies Act (PURPA) 1978, USA, 29 Qualified Coordinating Agency (QCA, 219 real-time market (RTM) framework, 191 regional load despatch centres (RLDCs), 162 Regional Power Committee (RPC), 164 regional transmission organization (RTO), 178 renewable energy certificate (REC) mechanism, 57, 61, 63, 108, 110, 122, 154–155, 203–208, 154 CERC notificiation in 2010, 139–142 forbearance price for, 141 for generators, eligibility criteria, 142–145 market performance of, 149–154

preferential tariff versus, 145–147 versus auctions, 209–210 wide divergence between states, 148–149 renewable energy in India, 221–223 approach to support, 32 auction process, assessment of, 201–203 commercial unviability of, 25 demand and net demand of a day, 181 issues and challenges, 4–6 need for infrastructure, 210–211 promotion under EA, 2003, 32–34 revolution of, 2–4 suggestions to improve, 211–220 targets for capacity addition, 112–115, 117–118, 120 tariff setting, 34–37 tariffs in states, 199–201 transmission pricing, 37–40 renewable energy in India, seamless integration framework ancillary services, 167–168 flexing thermal generation, 168–169 framework for forecasting and scheduling mechanism, 165–166 interconnection, 171 load variability in power system, 173 relaxation in Deviation Settlement Mechanism, 166–167 Index  231

smart grid, 170 storage and holding of electricity, 170 Renewable Energy Management Centres (REMCs), 222 renewable energy pricing in India, approaches actual project cost, 66 auction theory, 68–77 cost-plus, 62–63 international project cost, 66–68 market based, 65 regulatory, 64 renewable energy technologies global approach, 28–31 versus conventional technologies, 11 renewable portfolio standard (RPS) system, 35, 60, 106– 107, 211 renewable purchase obligation (RPO), 54, 73, 155, 211 drawbacks in, 121–122 in India, 110 in the UK, 108–111 issues in implementation of, 199 long-term growth trajectory of, 114 products in, 108 solar and non-solar, statewise, 115–118, 120 Report of the Comptroller and Auditor General of India on Renewable Energy Sector in India, 113 request for selection (RFS), 74 Reserves Regulation Ancillary Services (RRAS), 167 rooftop systems (RTS), 112

232  Renewable Energy in India

second-price sealed- bid auctions, 69 short-run marginal costs (SRMC), 35 short-run marginal costs (SRMCs), 20 short-term pool market, 22 Simpa Networks, 45–46 small-scale distributed renewable energy system, 42 Solar Energy Corporation of India (SECI), 73–77 solar plus storage model, 43 solar power projects, prices through bidding, 201 stand-alone system, 43 State Electricity Board (SEB), 8, 10–11 State Electricity Regulatory Commissions (SERCs), 5, 32, 52, 113 state load dispatch centres (SLDCs), 162 The Energy Research Institute (TERI), 48–49 transformers, 7 transmission access charge (TAC), 39 United Nations Framework Convention on Climate Change, 66 UP Electricity Regulatory Commission, 56 Uttar Pradesh New and Renewable Energy Development Agency (UPNEDA), 48–49, 56 wind power capacity, 3