Power System Assets: Investment, Management, Methods and Practices (CIGRE Green Books) 3030855139, 9783030855130

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CIGRE Green Books

CIGRE Study Committee C1: Power System Development and Economics

Power System Assets Investment, Management, Methods and Practices

CIGRE Green Books Series Editor CIGRE, International Council on Large Electric Systems (CIGRE), Paris, France

CIGRE presents their expertise in unique reference books on electrical power networks. These books are of a self-contained handbook character covering the entire knowledge of the subject within power engineering. The books are created by CIGRE experts within their study committees and are recognized by the engineering community as the top reference books in their fields. More information about this series at http://link.springer.com/series/15209

Graeme Ancell • Gary L. Ford • Earl S. Hill • Jody Levine • Christopher Reali • Eric Rijks • Ge´rald Sanchis Editors

Power System Assets Investment, Management, Methods and Practices

With 288 Figures and 41 Tables

Editors Graeme Ancell Ancell Consulting Ltd. Wellington, New Zealand

Gary L. Ford PowerNex Associates Inc. Toronto, ON, Canada

Earl S. Hill Loma Consulting Milwaukee, WI, USA

Jody Levine Hydro One (Canada) Toronto, ON, Canada

Christopher Reali Independent Electricity System Operator Toronto, ON, Canada

Eric Rijks TenneT Arnhem, The Netherlands

Gérald Sanchis RTE Paris, France

ISSN 2367-2625 ISSN 2367-2633 (electronic) ISBN 978-3-030-85513-0 ISBN 978-3-030-85514-7 (eBook) ISBN 978-3-030-85515-4 (print and electronic bundle) https://doi.org/10.1007/978-3-030-85514-7 © Springer Nature Switzerland AG 2022 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Switzerland AG. The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland

Message from the President of CIGRE

CIGRE is a global community of experts in electric power systems and equipment. It is a nonprofit organization based in Paris with members from over 100 countries. It functions largely as a virtual organization with members who are experts in their technical fields forming working groups dealing with issues facing the power generation and delivery industry. This unique community is underpinned by a global network of 60 CIGRE organizations referred to as the National Committees, or NCs. NCs also nominate their best local talent for the 250+ Working Groups participating in CIGRE’s global knowledge program. CIGRE is a source of technical information, unbiased by commercial considerations. The products of working groups are technical brochures, which are comprehensive reports addressing specific technical issues. The brochures are peer reviewed and practical in nature, which facilitate their application in their member utilities as required. CIGRE maintains an electronic archive for the over 700 brochures that have been published and as well for the thousands of technical papers that are presented and published at CIGRE conferences and symposia. In recent years CIGRE has initiated the development of CIGRE Green Books. These books comprise a compendium of material from CIGRE and other technical peer-reviewed publications and technical experts to document a comprehensive state-of-the-art report on broader technical fields. This Green Book on Power System Assets: Investment, Management, Methods and Practices compiled by Study Committee (SC) C1, Power System Development and Economics, provides guidance on asset management methods across a wide range of power system assets. Like other CIGRE Green Books, this book contains contributions from dozens of experts from around the globe. These international experts have provided technical information relevant to readers irrespective of where these readers reside. Apart from direct application of the Green Book’s information in utilities and other companies, this Green Book can be used as sources of information for development of international standards and technical guides, and for guidance to academics for the development of new methods.

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Message from the President of CIGRE

I would like to thank those involved from SC C1 and other Study Committees who have compiled or contributed to this book. I specifically want to address on behalf of CIGRE all my thanks and gratitude to Konstantin Staschus, past chair of SC C1 for initiating and contributing to this formidable project. January 2022-01-29

Michel Augonnet Michel Augonnet is a graduate engineer from Centrale Supelec in 1973. He was with the Alstom Group for 42 years in the field of power generation, transmission, and distribution (now GE), with a focus on electrical systems, control and instrumentation, project management, and sales. Michel is currently the president of the SuperGrid Institute (an electrical research and testing laboratory in Lyon France); a board member of AEG Power Systems, Mastergrid SA; and an alternate board director for ACTOM (PTY) South Africa. Michel is a former president of the French NC and President of CIGRE.

Message from the Chairman of the Technical Council of CIGRE

This Green Book titled Power System Assets: Investment, Management, Methods and Practices compiles the body of knowledge available from experts in the domain of asset management, as applied to the justification of asset investment on the areas of asset sustainment and system development. Senior utility managers and decision-makers along with regulators and interveners in regulatory processes are increasingly requiring quantitative financial justification for investments in both system development and asset sustainment. Remaining life assessment of aged assets and end-of-life management investments for aged assets are subject to stochastic processes. Proactive replacement through asset end-of-life definition depends on how much risk a utility is prepared to take in continuing to run assets versus the savings to be achieved through capital deferment. Justification for asset investment involves analysis of optional investments and their timing to determine which are optimal on a risk-based cost/benefit basis. Methods described in this Green Book provide a good fundamental basis for developing the complete business case including a spread sheet financial framework that can easily be adapted to the utility situation. Such methods need to make sense and be fully transparent in order to facilitate full understanding of the nontechnical or nonfinancial reviewers and decision-makers that will be needed to approve the resulting business cases. The use of this CIGRE Green Book, along with basic competency in the use of spread sheets, and rudimentary financial knowledge should allow users to successfully carry out the necessary analysis and development needed for the production of credible business cases. This Green Book has been authored by, and includes detailed case study contributions from, leading industry professionals acting as members of Study Committee (SC) C1 Power Systems Development and Economics and several other Study Committees. I take this opportunity to acknowledge the editorial team, the chapter authors, and all of the numerous contributors from which the entire global technical

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Message from the Chairman of the Technical Council of CIGRE

community will benefit. I especially wish to acknowledge and congratulate the leading role of Study Committee C1 and its chair, Antonio Iliceto, on the realization of this Green Book. Marcio Szechtman Chair, CIGRE Technical Council Marcio Szechtman graduated and received his MSc degree in electrical engineering from the University of Sao Paulo, Brazil, in 1971 and 1976, respectively. He joined CIGRE in 1981 and was Study Committee Chair of SC B4 (DC Systems and Power Electronics) from 2002 to 2008. He received the CIGRE Medal in 2014 and was elected chair of the Technical Council in 2018. Marcio has had a long career in R&D Power Systems Centers and since April 2019 was appointed Chief Transmission Officer (CTO) of Electrobras.

Message from the CIGRE Secretary General

In 2014, I had the pleasure to contribute an introductory message on the launch of the first CIGRE Green Book (Overhead Lines) and the second one (Accessories for HV Extruded Cables). The idea of the Green Books, to integrate the technical brochures of a given field into a single book, was first proposed by Dr. Konstantin Papailiou to the Technical Council in 2011. In cooperation with Springer, the first Green Book was published as a Major Reference Work and distributed through the vast network of this well-known international publisher. In response to the diverse needs of the Study committees, two other Green Book categories were created, namely a “Compact Series” for shorter more concise volumes and “CIGRE Green Book Technical Brochures.” CIGRE has published more than 850 Technical Brochures which are available in the online library, https:// e-cigre.org/ along with thousands of CIGRE conference and symposia papers. This library is one of the most comprehensive and accessible databases of relevant technical literature on power engineering. In the future, the Technical Council may decide to publish a technical brochure in the conventional way, but also as a Green Book in order that it be distributed beyond the CIGRE community using the Springer network. This new Green Book on Asset Management methods and practices is a Major Reference Work, prepared by Study Committee C1 Power Systems Development and Economics with contributions from several other Study Committees. Asset Management has evolved over the past two decades and continues to evolve in response to industry and regulatory needs. Therefore this Green Book, as a living ebook, will continue to evolve as required by advances in this discipline.

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Message from the CIGRE Secretary General

I want to congratulate all of the authors, contributors, and reviewers of this book for their tireless efforts in producing such a valuable resource for the industry. Secretary General

Philippe Adam Philippe Adam was appointed Secretary General of CIGRE in 2014. He is a graduate of École Centrale de Paris. He began his career at EDF in 1980 as a research engineer, advancing to management of a team of engineers researching HVDC and FACTS devices. In CIGRE his involvement initially as a working group expert and then as a working group convener was a support for his professional activities. Subsequently he held several management positions of increasing responsibility in EDF, and when RTE was formed in 2000, he was appointed manager of the Financial and Management Control Department and then in 2004 deputy head of the International Relations Department. From 2011 to 2014 he has been the strategy director of Infrastructures and Technologies of the Medgrid industrial initiative. Between 2002 and 2012 he served CIGRE as the technical committee secretary and as the secretary and treasurer of the French National Committee of CIGRE from 2009 to 2014.

Acknowledgments

Apart from authors acknowledged directly with their contributions in Part 2, the editorial team (hereinafter referred to as The Editors) would like to acknowledge and thank the Companies that provided the case studies in Part 2 and PJM for their copyright release to use copies of three PJM figures that appear in Chapter 3. In addition, The Editors very much appreciate the help, encouragement, support, and contributions of the following: Yves Maugain, Konstantin Staschus, Peter Roddy, Yury Tsimberg, Konstantin Papailiou, Simon Ryder, Terry Kreig, Bill Moore, Brian Sparling, John Lackey, Mark Vainberg, Megan Lund, Gerd Balzer, Marshall Clark, Wayne Pepper, and Philipp Schüett.

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Introduction

Asset management processes and organizational aspects are well documented in the ISO 55000 series and in several earlier SC C1 technical brochures. However, the major focus of this CIGRE Green Book is on documenting practical asset management methods. In order to bridge the so called “line of sight” or the gap between just satisfying an asset management process and achieving real asset management results, practical methods merging technical, financial, and risk analysis capabilities are needed to produce smarter investment decisions. Part 1 of this book describes the evolution of asset management, the business and regulatory drivers that have and continue to influence it, and the functional framework for asset management as developed in previous CIGRE technical brochures. Part 1 also documents the basic knowledge blending of the engineering and technical aspects of asset management in its various forms with the financial considerations needed to support asset investment decisions using risk-based business case analysis. While studying such technical/financial/risk-based methods is necessary, it is often even more instructive to see how the methods are applied in practice in the form of examples and detailed case studies. This part of the Green Book is intended to do just that. Part 2 of the book includes 10 case studies provided by utilities, an insurance company, and the editors, which demonstrate these methods as they are applied in practice. Each case study is introduced by an editorial team preface to provide context and links with Part 1 of the Green Book and as well to highlight key elements. These case studies have been included as submitted by the contributors with minimal to no editing, apart from correction of obvious English grammar errors that would lead to misunderstanding. The case studies also illustrate generic and specific or customized methods and the application of such methods from the equipment types and technology perspectives of several CIGRE study committees such as A1, A2, A3, B2, B3, and C1. Asset Management is a relatively new discipline that continues to evolve over time as influenced by changing business and regulatory environments. As such, this Green Book represents a snapshot in time of the best available information and thinking on Asset Management methods. The authors expect additional refinements as time goes on, and suggest all interested parties continue to follow this discipline through on-going efforts by CIGRE.

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Contents

Part I

Asset Management Methods: A Work in Progress . . . . . . . . .

1

1

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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TSO Business and Regulatory Influences on Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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Asset Management Investment Planning . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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Management of Aged Infrastructure . . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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Strategic Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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Operational Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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Tactical Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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Business Case Development for Support of Asset Management Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

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Contents

Summary and Outlook for the Future . . . . . . . . . . . . . . . . . . . . . . Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Gérald Sanchis

Part II Application of Asset Management Methods: Case Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .....

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Near-Term Asset Management Methods: TenneT and RTE Henk Sanders, Bob Okhuijsen, Eric Rijks, and Paul Penserini

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Transpower NZ Ltd.: Investigation into Targeted Equipment Servicing (as an Alternative to Replacement) of Disconnectors and Earth Switches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wayne Pepper and John Shann

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249 251

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Overhead Transmission Line Asset Sustainment Investment . . . . . Konstantin O. Papailiou and Gary L. Ford

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Transformer Sustainment Investment Options . . . . . . . . . . . . . . . . Brian D. Sparling and Gary L. Ford

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AusNet Substation Reinforcement: Maintaining Supply Reliability in North-Eastern Metropolitan Melbourne . . . . . . . . . . Herman De Beer and Andy Dickinson

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AltaLink: Transformer Repair/Replace Options . . . . . . . . . . . . . . Colin Clark and Ani Chopra

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Asset Fleet Management: “Bow Wave” Analysis . . . . . . . . . . . . . . Gary L. Ford

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Insurance As an Optional Asset Management Investment . . . . . . . Terence Lee, Terence Rademeyer, and Stuart Selden

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ESB Risk-Based Overhead Line Corridor Clearance Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jason Noctor, David O’Brien, and Oisin Armstrong

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Axpo – ERIS: A New Reliability-Based Planning Measure for Grid Investment Prioritization . . . . . . . . . . . . . . . . . . . . . . . . . Jörg Kottmann, Daniel Moor, and David Lehnen

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ENMAX Asset Failure Susceptibility Ranking . . . . . . . . . . . . . . . . Kevin Wan, Busayo Akinloye, and Truman Seto

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PJM: Probabilistic Risk Assessment for Spare Transformer Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hong Chen, David M. Egan, Kenneth Seiler, Michael E. Bryson, and Frederick S. S. Bresler III

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About the Editors

Dr. Graeme Ancell has worked in the electric utility sector for approximately three decades. Graeme is the owner of Ancell Consulting Limited, a company providing services to the electricity industry in New Zealand and internationally since 2015. He was the convenor of two C1 working groups and is a member of Study Committee C1.

Dr. Gary L. Ford has worked for Ontario Hydro and in the utility sector for more than four decades, Dr. Ford and two colleagues founded PowerNex Associates Inc., which provides technical consulting services to electric utilities in the area of asset management, procurement, and decision support. Since 1981, his CIGRE experience includes active participation in working groups 23.02, B3.12, C1.1, C1.16, C1.25, C1.38, B3.38, and D1.39, and most recently as Lead Editor for this Green Book.

Mr. Earl S. Hill has worked as an independent consultant to the electric utility industry for the past 30 years. He is the co-author of three EPRI publications on RCM and asset management. Mr. Hill has participated in CIGRE WG C1.25, WG C1.34, and currently WG C1.43. Mr. Hill has assisted in the implementation of maintenance improvement efforts for dozens of utilities, on every continent save Antarctica.

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About the Editors

Ms. Jody Levine has worked approximately three decades with the former Ontario Hydro and derivative companies. After spending several years as an operational asset manager for station equipment, she currently manages a group of field support consultants for maintenance of transmission stations. She has been active in CIGRE B1.60 and C1.43, and is chair of IEEE 400.3.

Mr. Christopher Reali is employed at the Independent Electricity System Operator (Ontario, Canada) in the role of Engineering Manager, Transmission Planning. Christopher has over a decade of experience in system planning. Christopher is active in NPCC, NERC, and CIGRE working groups. He is the Canadian national representative on SC C1.

Mr. Eric Rijks has been employed in the electric utility branch in the Netherlands for over two decades and is currently employed at TenneT Transmission System Operator. He was secretary of WG C1.1 and the convener of WG C1.16 and WG C1.25 which produced the four seminal CIGRE technical brochures upon which this green book is based. He was awarded with Technical Council Award. He holds an MSc in electrical engineering and EMSc in Internal Auditing.

Mr. Gérald Sanchis has been in the transmission business for over three decades, holding various positions in management and in technical fields within RTE and EDF group in France and Germany. He was deeply involved in ENTSO-E, for system development, R&D domains, and as support to the president of the association. He is a distinguished member of CIGRE and present convenor of C1.44, addressing the global grid issue. He was the coordinator of the R&D European project e-Highway 2050.

Contributors

Busayo Akinloye ENMAX, Calgary, AB, Canada Graeme Ancell Ancell Consulting Ltd., Wellington, New Zealand Oisin Armstrong ESB, Dublin, Ireland Frederick S. S. Bresler III PJM, Valley Forge, PA, USA Michael E. Bryson PJM, Valley Forge, PA, USA Hong Chen PJM, Valley Forge, PA, USA Ani Chopra AltaLink, Calgary, AB, Canada Colin Clark AltaLink, Calgary, AB, Canada Herman De Beer AusNet Services, Melbourne, Australia Andy Dickinson AusNet Services, Melbourne, Australia David M. Egan PJM, Valley Forge, PA, USA Gary L. Ford PowerNex Associates Inc., Toronto, ON, Canada Earl S. Hill Loma Consulting, Milwaukee, WI, USA Jörg Kottmann Axpo Grid AG, Baden, Switzerland Terence Lee FM Global, Johnston, IL, USA David Lehnen Axpo Grid AG, Baden, Switzerland Jody Levine Hydro One (Canada), Toronto, ON, Canada Daniel Moor Axpo Grid AG, Baden, Switzerland Jason Noctor ESB, Dublin, Ireland David O’Brien ESB, Dublin, Ireland Bob Okhuijsen TenneT, Arnhem, The Netherlands Konstantin O. Papailiou Malters, Switzerland xix

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Contributors

Paul Penserini Réseau de Transport d’Électricité (RTE), Paris, France Wayne Pepper Ausgrid, Sydney, Australia Terence Rademeyer FM Global, Johnston, IL, USA Christopher Reali Independent Electricity System Operator, Toronto, ON, Canada Eric Rijks TenneT, Arnhem, The Netherlands Gérald Sanchis RTE, Paris, France Henk Sanders TenneT, Arnhem, The Netherlands Kenneth Seiler PJM, Valley Forge, PA, USA Stuart Selden FM Global, Johnston, IL, USA Truman Seto ENMAX, Calgary, AB, Canada John Shann Ausgrid, Sydney, Australia Brian D. Sparling Dynamic Ratings Inc, Melbourne, Australia Kevin Wan ENMAX, Calgary, AB, Canada

Part I Asset Management Methods: A Work in Progress

1

Introduction Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Ge´rald Sanchis

Abstract

This chapter provides readers with background information on the evolution of asset management and the need for this CIGRE Green Book. The introduction provides an outline of the Green Book with samples of the information provided in each of the chapters in Part 1. The book includes detailed description of asset management analytical methods that are emerging or in development. While the methods documented in this book describe the current state of the practice and emerging methods, they also point to the need for utilities, businesses, and G. L. Ford (*) PowerNex Associates Inc., Toronto, ON, Canada e-mail: [email protected] G. Ancell Ancell Consulting Ltd., Wellington, New Zealand e-mail: [email protected] E. S. Hill Loma Consulting, Milwaukee, WI, USA e-mail: [email protected] J. Levine Hydro One (Canada), Toronto, ON, Canada e-mail: [email protected] C. Reali Independent Electricity System Operator, Toronto, ON, Canada e-mail: [email protected] E. Rijks TenneT, Arnhem, The Netherlands e-mail: [email protected] G. Sanchis RTE, Paris, France e-mail: [email protected] © Springer Nature Switzerland AG 2022 G. Ancell et al. (eds.), Power System Assets, CIGRE Green Books, https://doi.org/10.1007/978-3-030-85514-7_1

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G. L. Ford et al.

academics to develop better methods to value risk and to facilitate smarter and more profitable business investment decisions. Electric Power utilities have evolved and encountered significant changes and challenges over the past several decades. Economic recovery and growth through the 1950s, 1960s, and 1970s focused attention almost entirely on system expansion and development. Power system asset service lives were well within expected life spans, and international council on large electric systems (CIGRE) utilities were busy developing HV and EHV transmission systems along with equipment manufacturers who were busy developing products with higher voltage and capacity ratings. In the 1980s system growth in many counties slowed through periods of tougher economic times. In the 1990s, some governments that owned and controlled the electric utilities in their jurisdictions decided that electricity pricing could be better controlled through market forces than through direct regulation. Recognizing that the wires portions of the power system was a natural monopoly whereas the power generation side might become more efficient if left unregulated, many utilities were split up into transmission system operators (TSOs), distribution system operators (DSOs), and independent market and/or system operators (IES&MOs), which continued to be regulated, and an array of conventional generation companies that would operate along with any new generation companies, in an unregulated electricity market structure. As well, through the 90s, financial and competitive pressures on utilities to improve financial accountability and budgetary control resulted in many utilities reorganizing internally into asset centric structures. Conventional organizational structures had been designed to emulate the technical functions within a utility, so, for example, utility organizational structures would include a station maintenance department, a lines maintenance department, protection and control department, etc. These departments identified any work or investment required for equipment sustainment in their areas, while a system planning department looked after system development, system analyses (load flow, short-circuit, and system stability) to identify the need for any new investments in lines and substations, etc. As a result, budgetary requirements for all of these departments consisted primarily of funding for the costs of staff with additional materials costs added based on previous years’ results, or as a percentage of the staffing costs. This typical structure was relatively inflexible in terms of budget, and spending was focused on the need to support the staff as opposed to the specific needs of the assets. Senior utility management and regulators realized in the early 90s that improved justification for utility costs was required and, as well, in view of flat system growth in many of the developed countries, there was a need for increased organizational and financial flexibility. The solution adopted by many utilities was to move to the asset-centric organizational structure. In this style of organization, companies define the business functions as: the asset owner, the asset operator, the asset manager, and the asset services supplier (s). The Asset Owner could be a parent corporation in a private company setting, or the government or government department for public companies; the Asset Operator is an organization that takes responsibility for the proper operation of the over-all utility, which includes the Asset management function and Asset services functions. The asset services functions may deliver the required asset services or manage external suppliers supplying the necessary services. This form of organization effectively created the term asset management as a defined function. Of course, the assets had been managed for

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Introduction

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years very effectively by the kinds of functional departments described previously; but the creation of asset management-centric organizations created a whole new technical profession, spawning new organizations such as the Institute of Asset Management, new groups within CIGRE and other organizations focused on asset management, as well as new industry guides and standards related to asset management. For example it was about this time that CIGRE created a new working group WG37-27 Aging of the System and Impact on Planning was focused on populations of aging assets and their demographics in respect to their expected life. The concern and challenge that had been recognized was that in view of the significant system expansion through the previous 40 or 50 years that significant numbers of assets were approaching or beyond normally assumed end-of-life and would become unreliable and need to be replaced. The working group coined the expression “the bow wave” to describe the impending problem as illustrated below for a population of transformers that the group had surveyed. Mean and Standard Deviation of Asset Life Estimates 1600 1400 Population

1200 1000 800 600 400 200 0 0 to 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 5 Age in 1998 (Years)

This same type of demographic distribution exists for most other types of power system assets and TSOs continue to wrestle with this problem. Wholesale proactive replacement of assets would be prohibitively expensive and would create supply and pricing issues, not to mention regulatory restraint. Continuing to operate aged assets beyond normal expected end-of-life where the probability of failure, and maintenance costs increase year over year and with additional increasing reliability and customer service problems caused by run-tofailure strategies, creates increasing business and regulatory concerns. In response to these concerns CIGRE created WG C1.1 to follow-up the work reported in Technical Brochure (TB) 176 and to seek answers to questions such as: • What is the residual life of aged equipment? • Are remedial measures available, which would extend life and if so at what costs and for what benefit in terms of years of life extension? • If existing maintenance practices are continued, what failure rates can be expected and therefore what investment in spare components will be needed?

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Clearly there are numerous optional strategies that might be adopted, but they all involve trade-offs between performance, costs, and risk as illustrated by the following figure from TB 309 [WG C1.1, 2006].

Manageble Risk? Risk How much cost to manage risk and improve performance?

Cost

Performance

Time

Working Group C1.1’s framing of the asset management challenge as a risk management issue was continued by the subsequent working groups C1.16 and C1.25. This approach was also consistent with developments in a number of external organizations, namely, the Institute for Asset Management’s development of PAS 55 and the ISO’s development of ISO 33000 and ISO 33010, and recently the ISO 55000 series, which supersedes PAS 55. As well, the seminal publication of the UK government’s HM Treasury’s Green Book in 1997, was a regulatory response to motivate increasingly quantitative asset investment justification, through Enterprise Risk Management (ERM) methods. This important document, which will be discussed further in Chap. ▶ 8, was updated and elaborated in subsequent revisions, which continue in effect in the UK. As asset-centric organizations became the preferred organizational structure, it became evident that the asset managers focus and function in these structures differed widely. CIGRE working group C1.16 recognized this early in its work because it became evident during discussions with utility personnel whose titles used the words “Asset Manager” that they were, in fact, performing significantly differing functions. As a result, C1.16 developed an asset management functional framework to facilitate communications and consistent definitions of terms in TB 422 to describe three primary asset management functions, namely, Strategic asset management, Operational asset management, and Tactical asset management. In addition, the evolutionary development of asset management regulatory changes in many countries that were motivated to encourage cost efficiencies through competition created more complex business environments. Compared with the vertically integrated regulated utility that was the dominant utility structure in the twentieth century, the current array of reregulated non-vertically integrated utilities and other market players creates significant uncertainty and potential lack of coordination of investment. Planning for system development needs to be coordinated with plans for investment in sustaining existing infrastructure. Both of these investment areas need to

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Introduction

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be coordinated with possible investments in distributed and renewable generation, cross ¼ border energy or capacity acquisitions energy storage, energy efficiency technologies, electric vehicle (EV) technologies that change the use of the grid and make new demands on it, and any significant demand management initiatives. The integration of the asset management functions along with the complexity of coordination of asset management sustainment investment planning with system development asset investment planning is illustrated in the following figure.

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The strategic asset management function defines the asset management-centric organizational structure and provides the necessary authorities and parameters necessary for and within which the operational and tactical asset management functions perform their work. The operational and tactical functions need to work together to coordinate near-term and medium- to long-term asset investment planning while at the same time interacting with and coordinating with the system development planning function. Utility asset management organizations may not explicitly identify these three key asset management functions as departments within its organizational structure. Nevertheless these three functions need to be performed by utilities in order to satisfy minimal regulatory requirements for specified planning periods. The title of this green book is Power System Assets – Investment, Management, Methods and Practices. This title aligns with the primary focus of the book, while recognizing the developmental status of asset management. Asset management processes and their organizational issues have been effectively dealt with in the recent ISO 55000 series and in its predecessor, PAS 55. However, there is scant published information describing the details of the methods used in asset management to support investment decisions. This book aims to contribute up-to-date information on the methods and practices aspect of the asset management function and how asset investments are justified. An earlier draft title, “Asset Management Methods – a Work in Progress” was crafted by the editorial team to recognize that asset management methods have not yet developed to a mature technology stage. Unlike Green Books on OH lines, underground cables, transformers, etc., which have been developing into very mature technologies for decades, asset management methods are in development, and still responding to changing business and regulatory environments and demands. Therefore, the objective for this CIGRE Green Book is to produce a comprehensive living document that describes the state-of-thepractice of asset management methods as it stands in 2021. It includes information developed in CIGRE over the past two decades as well as key information related to asset management methods published by other technical organizations, government organizations, and utilities. It also includes new analytical methods and financial analysis methods adapted for asset management purposes from other purposes. We expect this CIGRE Green Book will be of value to users in all areas of utility asset management investment planning. The book is designed to have a handbook character and be a practical guide written at a tutorial level suitable for working asset managers and decision-makers (both engineering and financial) dealing with all aspects of the practice of asset management. As stated previously, the major focus of this book will be on documenting practical methods for bridging the so-called “line of sight” or the gap between just satisfying an asset management process and achieving real asset management results in the form of smarter investment decisions. Consistent with the scope of Study Committee C1, this book facilitates collaboration and blending of the engineering and technical aspects of asset management and the

1

Introduction

9

financial considerations needed to support asset investment decisions using riskbased business case analysis. Part 1 of this book describes the evolution of asset management, the business and regulatory drivers that have, and continue to influence it, and the functional framework for asset management as developed in previous CIGRE technical brochures. While studying the theory of such technical/financial/risk-based methods is necessary, it is often even more instructive to see how the methods are applied in practice in the form of examples and detailed case studies. Part 2 of the Green Book is intended to do just that. Part 2 of the book includes 12 case studies provided by utilities, an insurance company, and the editors, which demonstrate, in considerable detail, how these methods are applied in practice. The case studies also illustrate generic and specific or customized methods and the application of such methods from the technology perspectives of several CIGRE study committees. Chapter ▶ 2 describes utility business and regulatory environments and their relation to asset management. Included are the effects of asset management standards, directly or indirectly mandated by regulators on asset management practices, competency accreditation, process self-assessment, and audits of organizational asset management maturity. Proactive business and regulatory environments have motivated reliability standards, enterprise risk management (ERM)-based decisionmaking, performance-based regulation, valuation of lost load, all of which can have significant impact on asset management investment drivers and decision processes. Risk-based cost-benefit analysis methodologies are increasingly encouraged by leading regulators and used by leading utilities for investment justification and arbitration. Scenario methods are also very useful in tackling the uncertainty of long-term investments such as for assessment of optional transmission infrastructure investments. Thus, the use of risk management is confirmed for the selection of the priority actions within an organization. Cost-benefit analysis methods provide information about the impact and the benefits of action (e.g., investment in new infrastructure, or refurbishment of existing). The scenario methodology places the options in perspective, thus facilitating comparison between different potential solutions. Chapter ▶ 3 deals with the coordination of system development and asset sustainment, investments, coordination of investments in the transmission system versus the distribution system, investment in hard assets versus investment in demand management, the trade-off between CAPEX and OPEX within sustainment investment plans, and the application of innovative and new technologies options for solutions of grid problems versus conventional grid development options. While there are uncertainties involved in justification of asset sustainment investments as discussed in Chaps. ▶ 6, ▶ 7, and ▶ 8, the area of investment in system development is increasingly complex and uncertain. System development planning requires insights and information on how system demand will vary over planning periods comparable with the typical lives of assets, namely, 40 or more years. Demand

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forecasts over such time frames will be significantly affected by variability of country and global economies, major environmental initiatives such as to reduce carbon use in heating and transportation, government responses and actions, and the actions of regulators. For example, the trend for governments globally to support Net Zero or climate initiatives for 2050 or shortly after will have dramatic impact on electric power system development. In the UK National Grid ESO (Electricity System Operator) projects system demand to follow optional trends as shown in the following figure. Electricity peak demand (including losses) 100 90

GW 70 60 50 2010

2015

2020

2025

2030

2035

History

Consumer Transformation

Leading the way

Steady Progression

2040

2045

System Transformation

2050

FES2020 / System view / introduction 57

80

This projection illustrates a system demand slightly deceasing in recent years; but then increasing by approximately 30–60% over the next 30 years depending on assumptions regarding how aggressively the net zero 2050 challenge is taken up, and whether it will follow rather decentralized vs. continental-scale integration paths. Despite common net zero goals, which limit the diversity of possible scenarios, governments in countries around the globe will take their own approaches, as will their regulators. Utilities cannot adopt a wait and see attitude because of the extended lead times required to procure and commission power system facilities and assets. There are significant risks in under or delayed investment and there are significant cost penalties for over or premature investment. In addition to demand uncertainty, scientists predict that global warming trends will result in increasingly severe and frequent storms. Such storms impact electric power systems and their customers and can cause extended outages and very significant repair costs. Utilities and regulators are concerned about increasing electric power system resiliency, but how much to invest to build adequate resiliency is a question requiring careful weighing of risks, benefits, and costs.

1

Introduction

11

The outlook over the next few decades for system development and asset sustainment investment planning appears to be uncertain at the least if not unpredictable, but nonetheless, crucial decisions need to be made each year. Chapter ▶ 4 is focused on the management of aging infrastructure. There are several factors that can influence the aging behavior of assets as illustrated below. Clearly there are asset management tradeoffs to be considered and made in respect to design conservatism and equipment specification, how much to invest in maintenance programs and over the expected life of assets, and issues related to operational duties compared with ratings; but all of these decisions influence the aging behavior of assets.

Electric power system assets are designed to withstand expected levels of electrical stresses such as transient high voltages and environmental stresses such as extreme winds and ice/snow loading. Materials used in assets age wear out and have a lower ability to survive stresses, and therefore aged assets become more likely to fail under the design electrical and environment stresses as illustrated below. Assets can reach end of life by failing catastrophically in service or through a failure that is not repairable or uneconomic to repair. A determination of the end of life for an asset is possible if an assessment of its condition deems the asset no longer able to meet the

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performance required for that asset and that the risks of continued operation are unacceptable. End of life can occur through asset deterioration, obsolescence, changed asset performance requirements, and asset failure. Assets deteriorate with time and usage, which reduces the performance of the asset. Assets may become obsolete as manufacturers cease making and supporting the assets. The performance required of assets can change over time and the existing assets may not meet new performance requirements. Assets can fail through many different modes and some types of failures may render the asset unusable. The consequence of deteriorating asset performance is an increasing risk of failure of the asset. The asset may fail causing losses of supply, constraints on generation, and danger to the public and staff members. In-service failure may have severe consequences for the environment and reputation of the organization owning the assets. Shareholders and regulators have a considerable interest in trends in asset performance, particularly declining trends. A good understanding of how assets age in service, the factors affecting the rates of aging, the failure modes, and the consequences of in-service failures provide important underlying information for operational and tactical asset managers in their considerations of actions and investment decisions as described in Chaps. ▶ 6 and ▶ 7. Chapter ▶ 5 outlines Strategic Asset Management function in an organization. The strategic asset management function is realized by the utility’s senior executive team representing the owner in the case of a utility owned by a government or the owners in the case of a company owned by shareholders. There may or may not be a person with a title such as VP asset management, but the key strategic responsibilities to: • Commit to an asset centric management style. • Create the corresponding organizational structure.

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Introduction

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• • • •

Define key performance indices and measures. Approve key financial parameters for business case analysis. Decide the corporate risk appetite. Decide to self-insure rather than insure commercially as a risk mitigation strategy, and so on.

will be performed at the senior executive level in most utilities. All of these key decisions and initiatives need to be approved by the CEO and executive team and likely the board on behalf of the owner/shareholders. How top corporate executives identify the goals of the organization, how they ensure the program has the “teeth” to accomplish those goals, and how they manage risks associated with the utility defines the strategic asset management function. Strategic Asset Management provides direction in the form of documented policies and guidance to the Asset Management team and reviews the process for turning objectives into metrics for the organization. Company stakeholders and regulators provide input for company objectives. Senior management considers the shareholders and “owners” of the company, but must also consider the desires of a wide range of other stakeholders. The following figure lists some of the stakeholders and what they consider important for a utility in Europe.

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From the objectives, Strategic Asset Management must put those goals into practice in order to ensure they are achieved. To do this, top managers create a framework leading eventually to Key Performance Indicators (KPIs) (and performance contracts), which provide the managers with measures of the performance and the condition of the company. The following table shows some key performance indicators from one European company, along with past performance and the targets for the subsequent year. The objectives here have been translated into “Impact Area.”

SDG

13

Impact area

Climate

Target

KPI identified

To be climate neutral for our substations, offices and mobility in 2020. To be fully climate neutral (SF6 CO2 footprint of our substations, emissions, grid losses, energy use offices and mobility (net emission in offices, stations and mobility of our tonnes of CO2) employees) in 2020. < 0.28% in 2020 SF6 leakage (%) SF6 leakage (kg)

12

Circularity

< 1,106kg in 2020

(Net) impact on nature 2)

In 2025 25% less impact on virgin copper use1) In 2025 25% less impact of non-recyclable waste1) Zero (net) impact on Nature in 2020

Oil leakages (litres)

50% reduction of oil leakage in 2020, compared to 2017

Reduction of virgin copper use Reduction of non-recyclable waste

14

2018

2017

2016

2,037,122

2,095,129

1,709,354

0.30%

0.28%

0.38%

1,069

934

1,248

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

6,379

6,860

2,087

Nature

15 1 2

Not applicable as 2020 will be our base year. This KPI is currently in progress.

Climate 2018

Climate Gross carbon footprint (ton CO2o)/transported electricity (GWh) Grid losses (GWh)

2017

2016

10.5

10.8

9.3

5,040

5,080

4,212

Sometimes, the most critical KPI outline system performance, such as the following reliability target from the Network Output Measures (NOMS) as defined by the regulator OFGEM in the UK: ii Reliability Minimise how much electricity is lost to our customers because of failures of the assets on the network

2017/18 targets NGET: less than 316 MWh SPT: less than 225 MWh SHET: less than 120 MWh

All below target

1

Introduction

15

To achieve the objectives, senior management puts in place a number of directive documents; the most important of which is the Strategic Asset Management Plan. Illustrated below is a sample table of contents from an Australian utility:

Contents Message from the GM Strategic Asset Management Chapter 1 Introduction and Context Chapter 2 Asset Management System Framework Chapter 3 Strategic Asset Management Considerations Chapter 4 The Tasmanian Power System Chapter 5 Organisational Roles and Responsibilities Chapter 6 Leadership and Culture Chapter 7 Risk Management Chapter 8 Future Demand Requirements Chapter 9 Life-cycle Strategies Chapter 10 Management Plans Development Chapter 11 Performance Evaluation and Improvement Appendix A Asset Management Policy Appendix B Zero Harm Policy Appendix C Glossary and abbreviations

2 3 7 11 23 33 35 37 43 47 55 59

71 72 73

Asset Management formalizes risk in the decision-making process. Utilities have in the past always considered risk, but typically in an inconsistent and ad hoc manner. Strategic Asset Management provides guidance for risk-based decisions, starting with the concept of the risk matrix in the operational asset management function (Chap. ▶ 6). This technique allows the company to assess the probability and the associated consequences to assess in qualitative terms the risk. The strategic asset management function also provides guidance and necessary direction to the tactical asset management function (Chap. ▶ 7) where risks are assessed at a higher quantitative level for optional projects. In summary, Chap. ▶ 5 deals with the strategic functions of asset management. In asset-centric organizational structures the leadership of senior management is a critical factor. As well, definition of shareholder and regulatory risk attitudes need

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to be defined and communicated. Chapter ▶ 5 deals with these and other topics including, corporate financial constraints/incentives, corporate business values – definition and monetization, and corporate policies on asset insurance. Chapter ▶ 6, operational asset management, describes the asset management function, which deals with the shortest time horizon, and relates to asset decisionmaking at its most granular level. Decisions revolve around prioritizing which devices to target with replacements, which maintenance activities to choose, and when is the best time to perform them. Operational asset management follows an ongoing process as illustrated below.

Understanding failure modes, with their probabilities and consequences, is essential. Condition assessment is fundamental to deciding what mitigations to apply and when. A range of testing and data collection methods are necessary to determine which populations are in what condition. Failure modes vary with asset type and severity and therefore require different types of remediation. Investment in gathering equipment condition and criticality data is necessary to provide a quantitative basis for prioritization of maintenance actions and investment. The different types of data range from static to continuous time stream; each have different collection and storage requirements. Operational asset management focuses on near-term asset investment planning, such as more versus less maintenance, timebased vs. condition-based vs. reliability centered maintenance (RCM), etc., and

1

Introduction

17

mixtures of these, asset repair versus end-of-life management, asset overloading vs. loss of life decision-making, and so on. Analytic tools can be used to process health index/criticality data to provide population snapshot reports to facilitate prioritization of asset investment needs. Shown below is an illustration from an asset analytics software used in New Zealand.

RAB Regulatory Asset Base Operational asset managers use asset registries and asset data management tools, asset condition assessment, asset monitoring data, and interpretation, health indices, and criticality to justify and rank near-term asset investment decisions, as well as spares and spare parts utilization/planning. Chapter ▶ 7 focuses on the tactical asset management function, which includes medium- to long-term asset planning and coordination between asset sustainment and system development investments under practical resource, financial and regulatory constraints. It is a complex process involving engineering understandings of asset aging processes as discussed in Chap. ▶ 4, financial analysis and risk analysis understandings as discussed in Chap. ▶ 8. The asset sustainment portion of the process is illustrated below.

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The techniques discussed include risk identification and quantification, spares planning, investment timing, performance measures and management, asset management policy options for investment in risk treatments such as, refurbishment, replacement, run with on-line monitoring, run as is, to defer investment, buy insurance, and temporary solutions. The chapter includes examples of utility’s optional investment tactics such as illustrated in this figure from the Australian utility SP AusNet.

1

Introduction

19

Option identification Typical asset renewal options include: OPTION 1: Business as Usual › Continue to maintain and operate existing plant. › Safety risk and maintenance costs increase with time as asset condition deteriorate. › Set base line risk by which to compare other options.

OPTION 2: Integrated asset replacement › Like-for-like replacement of all assets with poor conditions score. › In cases where a number of assets require replacement, major station rebuild takes advantage of project synergies not available for single asset replacement. › Risk and maintenance costs will be reduced compared to Option 1 due to improved asset condition.

OPTION 3: Defer replacement through asset refurbishment or operational measures

Probabilistic Planning accepts and measures risk

› Develop contingency plans for asset failure events e.g. temporary load transfers, holding of spares which can be used across a number of stations. › Increased maintenance costs but reduced capital expenditure i.e. CAPEX / OPEX trade-offs.

15

Chapter ▶ 8 documents methods for risk-based investment business case analysis. This includes investment decision justification methods, information requirements, data availability, in-house data, industry survey data, data mining from big data, risk-based business case analysis processes, methods and tools, monetization of business values and consequences of failures, use of optimism factors or a risk premium in business case analysis, and use of sensitivity analysis. The evolution business case analysis guidelines and requirements as motivated by various government agencies and as implemented in spreadsheet-based business case analysis from earlier CIGRE technical brochures is discussed. The chapter includes sufficient detail for readers to easily implement the analysis methods for their own applications. It includes annotated spreadsheets such as shown below for analysis of sparse failure data and for more complex spreadsheet analysis and the chapter includes the results for worked practical examples as illustrated below for a study of the optimum timing of an aged transformer depending on service area and differing financial parameters.

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Suburban - Medium Impact Costs NPV Risk + CAPEX (k$)

$4,000 $3,500 $3,000 $2,500 $2,000 $1,500

IR/DR 2%/5%

$1,000

IR/DR 2%/8%

$500 $Run to failure >2034

Replace Replace Replace Replace 2019 2024 2029 2034

NPV Risk + CAPEX (k$)

City Centre High Impact Costs $5,000 $4,500 $4,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $-

IR/DR 2%/5% IR/DR 2%/8%

Run to failure >2034

Replace Replace Replace 2019 2024 2029

Replace 2034

1

Introduction

21

The concluding Chap. ▶ 9 of Part 1 provides a summary perspective on the current state-of-the-practice of asset management and an outlook on needs and issues for further development. Twelve comprehensive asset management case studies are included in Part 2 to provide detailed descriptions of the methods used for investment risk management, trends and new solutions as illustrated through case studies from both DSOs and/or TSOs and from generation companies to illustrate differences and common approaches.

References CIGRE WG37-27 Technical Brochure 176 “Ageing of the System Impact on Planning” 2000 CIGRE WG C1.1 Technical Brochure 309 “Asset Management of Transmission Systems and Associated CIGRE Activities” 2006 CIGRE WG C1.16 Technical Brochure 422 “Transmission asset Risk Management” 2010 HM Treasury the Green Book – Appraisal and Evaluation in Central Government 1997 original revised to currently available 2015 edition. https://www.gov.uk/government/uploads/system/ uploads/attachment_data/file/469317/green_book_guidance_public_sector_business_cases_ 2015_update.pdf IAM PAS 55 Competency Requirements Framework, 2006 ISO 33000 Risk Management – Principles and Guidelines on Implementation ISO 31010 Risk Management – Risk assessment Techniques

2

TSO Business and Regulatory Influences on Asset Management Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Ge´rald Sanchis

Contents 1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Summary of Relevant CIGRE TB . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 Utility Business and Regulatory Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 TB 327: Impact of Regulatory Environments on Investment Decision and Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3 TB 474: Interface Between System Operators End Regulators . . . . . . . . . . . . . . . . . . . . . . 2.4 TB 565: Regulatory Incentives for Capital Investments in the Electricity System . . . 2.5 TB 597: Transmission Risk Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6 TB 667: Risk Management in Evolving Regulatory Frameworks . . . . . . . . . . . . . . . . . . .

24 25 25 25 26 26 27 28

G. L. Ford (*) PowerNex Associates Inc., Toronto, ON, Canada e-mail: [email protected] G. Ancell Ancell Consulting Ltd., Wellington, New Zealand e-mail: [email protected] E. S. Hill Loma Consulting, Milwaukee, WI, USA e-mail: [email protected] J. Levine Hydro One (Canada), Toronto, ON, Canada e-mail: [email protected] C. Reali Independent Electricity System Operator, Toronto, ON, Canada e-mail: [email protected] E. Rijks TenneT, Arnhem, The Netherlands e-mail: [email protected] G. Sanchis RTE, Paris, France e-mail: [email protected] © Springer Nature Switzerland AG 2022 G. Ancell et al. (eds.), Power System Assets, CIGRE Green Books, https://doi.org/10.1007/978-3-030-85514-7_2

23

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G. L. Ford et al. 2.7

TB 692: Market Price Signals and Regulatory Frameworks for Coordination of Transmission Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.8 TB 715: The Future of Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.9 TB 726: Asset Management for Distribution Networks with High Penetration of Distributed Energy Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.10 TB 764: Expected Impact on Substation Management from Future Grids . . . . . . . . . . 2.11 TB 786: Investment Decisions in a Changing and Uncertain Environment . . . . . . . . . 3 Regulatory Drivers for Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 TSO/DSO Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Efficiency and Performance Stimulated by Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 Impact of Regulation for Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 New Regulatory Initiatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 DNO Common Network Asset Indices Methodology Mandated by OFGEM` . . . . . . . 4.2 Transmission System Network Output Measures Fixed by OFGEM . . . . . . . . . . . . . . . . . 4.3 Benefit-Cost Analysis in the REV Context in New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4 Projects of Common Interest Put in Place in Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5 Proposal for Ontario Energy Board to Advance Innovation in Energy Sector . . . . . . . 4.6 Australian Energy Regulator (AER) Asset Management Industry Practice Application Note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

28 29 29 29 30 30 30 31 32 33 33 34 35 36 37 37 38 39

Abstract

Review of relevant CIGRE publications provides an overview of the evolution of the impact of regulations on asset management. Thus, methods were developed by utilities to prioritize the needs and actions within a fixed budget. More recently, additional transmission needs have been recognized for the implementation of increased levels of renewable energy sources. These additional needs have led to new asset management approaches, new methods for better investment and expenditure assessment, and prioritization. The use of risk management is confirmed for the selection of priority actions within an organization. Cost-Benefit Analysis methods provide information about the impact and the benefits of action. Scenario methods place the action in perspective, facilitating comparison between different potential solutions.

1

Introduction

This chapter introduces and discusses utility business, regulatory, commercial environments, and their relationship to the evolution of utility asset management. Included are the effects of asset management standards, mandated directly or indirectly by regulators on asset management practices, skills, accreditation, process self-assessment, and organizational asset management maturity audits. The chapter begins with a summary of CIGRE publications (Technical Brochures or TB), which have addressed technical business and regulatory issues related to asset management. The text is based on the referenced publications. Then, the main drivers of asset management from a regulatory perspective are discussed. The last part of this chapter presents some of the aspects of the new asset management

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25

expectations, taking into account utility experience, and the evolution of business and regulatory environments.

2

Summary of Relevant CIGRE TB

2.1

Utility Business and Regulatory Environments

For decades, the traditional business model in operation was an integrated utility from generation through to customer supply, controlling the entire energy delivery value chain.In many countries, this model has been supplanted in various forms to become more market and customer oriented. New entities have been introduced, such as energy suppliers, integrators, enablers, and optimizers with different points of focus along the value chain. Each actor of this new value chain faces different challenges and aims using different business models. In this background, the transmission operators are more system-focused with a new role of an integrator. They are at the same time network managers and also grid developers, operating under the constraints of regulatory rules. Regarding asset management, the regulators typically require that utilities demonstrate good practices. They may impose different requirements and expect leading asset management practices such as indicated by utility certification (e.g., ISO 55000), self or external audits, including regular publication and updating of asset management plans. From the perspective of sharing best practices, and experiences, this section introduces the relevant CIGRE Technical Brochures that have addressed regulatory issues that influence the asset management.

2.2

TB 327: Impact of Regulatory Environments on Investment Decision and Transmission

Technical Brochure 327 was published in 2007 by the WG C6.1, and describes the “Impact of regulatory environments on investment decision and transmission.” This title helps readers to understand the impact of the regulatory environment on asset management through the authorization of investment. The regulatory system design must be robust enough to meet the objectives of providing sustainable incentives for TSOs to improve efficiency while also providing sustained and demonstrable benefits to consumers. Thus, insufficient return on asset investments allowed by regulators can limit the TSO’s ability to fund projects. Non-recovery of the costs of stranded transmission assets creates greater pressure on TSOs to ensure robust transmission plans. When the regulator decides to reduce the level of capital allowed for new projects, refurbishment projects are the ones most likely to be postponed, impacting future transmission plans. However, postponement of refurbishment may lead later to higher operating expenditures.

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TB 474: Interface Between System Operators End Regulators

Technical Brochure 474 was published in 2011 by WG C5.5 and describes the “Interface between System Operators and regulators.” The TB summarizes the results of a survey launched by CIGRE on the relationship between System Operators and Regulators. The main transmission network system organization models are summarized: the TSO (Transmission System Operator) and the ISO (Independent System Operator) models. The TSO typically owns and operates the transmission system, and is responsible for the development of the system. In jurisdictions with the ISO model, there is an independent body responsible for the operation of the transmission system. This model has its special advantages when there is more than one owners of the transmission system. In such a case, the decisions and priorities taken in the system operation have a different impact on the use of the system and also on the allocation of revenue. The TSO model has been widely used in Europe, while the ISO is the main model in North-America. The survey results highlight the importance of achieving operating cost reduction in all countries. Generators are subject to market competition. Transmission Operators are under pressure by the regulator. Due to the monopolistic nature of transmission systems, the regulator aims for operators of the system to deliver high quality and efficiency at low cost. Another aspect that drives the need to maximize use of existing facilities is the difficulty of building new transmission lines. Innovative programs are therefore in force to maximize the use of the existing system and to allow deferment of expenditure.

2.4

TB 565: Regulatory Incentives for Capital Investments in the Electricity System

Technical Brochure 565, published in 2013 by WG C5.10, describes the “Regulatory incentives for capital investments in electricity system”. The objective of this TB is to provide a framework, describing experiences in several countries and drawing practical conclusions about regulatory provisions to encourage investment in network infrastructure and electricity production. Conceptual work is supported by empirical investigation for several countries using a questionnaire. In this respect, the TB clarifies and differentiates investments linked to the extension of the network, versus investments linked to the sustainment and replacement of the existing network. Investments in the extension of the network are necessary to respond to the change in load and production patterns in the future. Investments in the distribution network are mainly made for a specific customer or a group of customers, while investments in transmission networks tend to result from an increasing load in a specific network area (or today, from renewable energy investments). In general, transmission network planning is based more on forecasts and less on individual

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applications for new connections. In addition, extensions to the transmission network generally take longer to complete than those to distribution networks. Transmission projects are not numerous but generally larger, resulting in an irregular increase in capacity. Network sustainment replacement investments are generally linked to refurbishment or replacement of old equipment (technically or economically). Traditionally, in many countries, equipment has been replaced after some specific service life or, for example, at its economic end of life. Due to such conservative estimates, this practice resulted in a situation characterized on the one hand by highly reliable equipment and systems, but on the other hand by costly replacements, which could probably have been deferred. The other extreme is to replace the equipment only in the event of a failure. For energy networks, this means in many cases, either a direct interruption of supply or a reduction in the reliability of the system or both. A third approach, using condition-based maintenance provides a good compromise. According to this method, maintenance and replacement decisions for equipment are no longer based on a fixed number of years, but rather on the actual and historical condition of the equipment that is continuously assessed. This approach is based upon measurements and knowledge rules to determine if and when maintenance or replacement of specific equipment should occur. In some cases, the investment cannot be characterized as a single type of investment as indicated above, but must be divided into two categories. For example, when a transformer needs to be replaced due to aging, it might be considered prudent to increase its capacity at the same time. In this case, the investment will be both for reasons of network extension and for reasons of replacement. Investment needs can also result from changes in the legal obligations or system reliability compliance standards. For example, if new occupational safety rules require additional safety measures in substations or high voltage transmission lines, this can lead to new investments. Such Investments do not lead to an increase in capacity, or the replacement of aged components.

2.5

TB 597: Transmission Risk Management

Technical Brochure 597 was published in 2014 by WG C1.25 and discusses the “Transmission Risk Management,” with an emphasis on the regulatory environment. The risk management approach applied by utilities is useful for prioritizing preventive actions on assets based on the specific parameters applied in performance-based regulation. For some TSOs, regulatory impacts are included in the business values, which are taken into account in the business impact matrix used to classify preventive actions according to the severity of the impact. In its conclusions, the TB recommends the use of asset management standards, such as ISO 55000, for organizational and asset management processes and good governance of electricity transmission companies. These standards facilitate the transparency and clarification expected by regulatory authorities. The TB highlights

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the new critical areas of asset management, in the short and long term, and linked, in particular, to new constraints with the development of intermittent sources of generation.

2.6

TB 667: Risk Management in Evolving Regulatory Frameworks

Technical Brochure 667 was published in 2016 by WG C5.15 and compares the “The Risk Management in evolving regulatory frameworks” on different markets. The TB provides a benchmark from 13 different countries, covering the main topics: trading timeframes, trading logistics and detail, clearing houses and settlements, and defaults. The scope is mainly market and finance oriented. It underlines the importance of risk management method for regulatory activities.

2.7

TB 692: Market Price Signals and Regulatory Frameworks for Coordination of Transmission Investments

Technical Brochure 692 was published in 2017 by WG C5.18 and discusses “Market price signals and regulatory frameworks for coordination of transmission investments.” The TB is structured with the following three sections: Transmission organization models, electricity market and network tariff schemes, and regulatory schemes. The last section, on regulatory schemes, addresses topics related to asset management. Thus it focuses on cost benefit analysis and cost allocation, which are key aspects of the management of transmission asset investments. The survey carried out by WG C5.18 prior to 2017 shows that in many areas, increased demand was no longer the main driver for investment. The new drivers are the integration of cross-border markets, the integration of new intermittent renewable generation, and improvement of security of supply. Thus, many TSOs are currently facing significant investments in the transmission capacity of the network, while the actual use of the transmission network may decrease in the future due to energy efficiency and the increase of decentralized generation. In the past, networks have been built to ensure the unidirectional transfer of electricity from large power plants to passive consumers. Nowadays, investments in networks are partially driven by the evolution of generation patterns resulting from the integration of markets, the implementation of Renewable Energy Sources, and the development of localized self-generation. The development of small generators, active consumers, and prosumers, for the most part connected at the distribution level, leads to decreasing, more variable and sometimes even negative withdrawals from the transmission network. The transmission network is increasingly used as an insurance against local shortages. Therefore, despite less use of transmission, the need for transmission capacity remains the same or may even increase in the future under the influence of de-carbonization of heat and transportation.

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TB 715: The Future of Reliability

Technical Brochure 715 was published in 2018 by WG C1.27 and addresses the topic of “The Future of reliability: definition of reliability in light of new developments in various devices and services which offer customers and system operators new levels of flexibility.” The TB emphasizes the need to change the definition of reliability in light of the recent changes in networks. In recent years, a number of new technologies providing energy, capacity, and other grid services have become available. It is likely that a large portion of the future generation mix will consist of distributed energy resources. These new resources may ultimately replace conventional generation, which traditionally provides frequency response, voltage control, and other services. The need to change the definition of reliability is motivated by these developments, the significant increase in user options to self-supply or supply power to the system, and various new technologies that provide new types of operating flexibility. The TB proposes new definitions of reliability, adequacy, and security. It is important to find common definitions within the TSOs community, as this type of definition should intend to be used by the regulatory authorities to assess the performances of TSOs. In the past, some regulators, such as North American Electricity Reliability Corporation (NERC) have developed their own definitions. The new definitions proposed by CIGRE have the advantage of a common agreement within a large international group.

2.9

TB 726: Asset Management for Distribution Networks with High Penetration of Distributed Energy Resources

Technical Brochure 726 was published in 2018 by WG C6.27 and discusses “Asset Management for distribution networks with high penetration of distributed energy resources.” The TB provides an international overview of current practices in asset management practices and gives an example of the application of the scenario technique to the management of distribution networks with high penetration of distributed energy resources. In its conclusion, the TB underlines the key role of regulation in improving the expected development of new flexibility services by encouraging innovation and deployment of new technologies.

2.10

TB 764: Expected Impact on Substation Management from Future Grids

Technical Brochure 764 was published in 2019 by WG B3.34 and explores the “Expected impact on substation management from future grids.”

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The TB provides a perspective on factors that could influence the direction of future substation design and management following future energy scenarios. A focus is made on changes in the energy landscape and new technological developments that can challenge the designer in their traditional way of thinking and, therefore, affect the design process and asset management strategy of future substations. In the new regulatory context, maintenance strategies based on temporal or time based, corrective, or preventive are less likely to be applied. They are generally considered to create higher unit costs for maintenance activities and can lead to inefficient use of resources. The TB introduces risk management as a key driver for the definition of new maintenance strategies. In addition, the use of dynamic rating management, new sensors, and new IT tools are encouraged in order to maximize the inherent loading capacity and therefore to reduce the need for new investments.

2.11

TB 786: Investment Decisions in a Changing and Uncertain Environment

Technical Brochure 786 was published in 2019 by WG C1.22 and addresses “Investment decisions in a changing and uncertain environment.” WG C1.22 carried out a survey in order to capture the change applied by TSOs in their investment process, taking into account the needs for a low carbon future. In this regard, the use of scenarios plays a key role in addressing uncertainty in transmission investment decisions, and the necessary approval by the regulatory authorities.

3

Regulatory Drivers for Asset Management

3.1

TSO/DSO Revenues

Transmission and distribution networks are generally considered as natural monopolies for a country or region, in which competition is limited or even nonexistent. The aim of regulation is often to prevent network owners from achieving excessive profits from a monopolistic situation and to ensure that networks are operated as cost efficiently as possible. The revenues of transmission networks typically depend on transmission tariffs defined by the regulation. Transmission tariffs generally reflect costs, taking into account the historical costs of the network and the projected costs over the current regulatory period. The transmission tariff needs to allow recovery of costs incurred by the monopoly transmission owner, while stimulating efficiency. Cost recovery is usually the central objective of the tariff structure. Efficiency mainly concerns the cost-reflectivity and the economic signals sent to the network users for optimal use of the network. The structure of the transmission tariff should reflect the structure of the transmission costs. A cost-reflective tariff can be differentiated according to place and time. The location signals are related to differences in congestion costs and losses

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between the different network nodes. Time signals can be a useful tool to reduce system peak-load, which is a main driver for network investments. The costs recovered by the transmission tariffs include the financing costs of capital expenditure (CAPEX), and operational expenses (OPEX). CAPEX is covered through the depreciation and profitability of transmission Investments. OPEX includes costs such as the cost of maintenance, cost of system operation. The cost of the transmission losses, ancillary services, system balancing energy, and congestion management are usually included in OPEX costs. However, in some jurisdictions, these costs are excluded from OPEX, and are managed within wholesale market arrangements. TSOs are authorized to realize a return on investment (ROI). The most popular approach is to use the nominal WACC (Weighted Average Cost of Capital) before tax to determine acceptable investment return levels. The Regulatory Asset Base (RAB) serves as a fundamental parameter in utility regulation in order to determine the authorized profit. The RAB is the value of net invested capital based on regulatory rules. In general, the RAB provides for remuneration of all existing and new investments for assets that are in service.

3.2

Efficiency and Performance Stimulated by Regulation

Most regulators expect more transparency on transmission costs and improvement of efficiency. TSOs have been stimulated to develop more rigorous and quantitative methods for business case analysis in order to justify investment in assets. Market competition is normally the main driver to incent companies to be efficient.Since transmission system operators do not face competition, incentive or performance-based regulation is a key instrument used by regulators to boost competition and reward efficiencies. The extent of a transmission owner’s profitability and efficiency can be assessed through studies comparing the performance of different companies against each other, rather than examining the costs of a single company in isolation. In this regard, benchmarking provides a useful approach for assessing the effectiveness of the regulation of a monopoly activity. Some regulators formally require that transmission and distribution businesses disclose sufficient information to allow such performance and quality comparisons. The performance of transmission owners expected by regulators is not just limited to the costs, but also includes quality. Both quality and cost/revenues need to be maintained within acceptable limits. These arrangements are intended to avoid under investment in assets at the expense of the quality experienced by customers. Performance-based regulation emphasizes optimization of overall asset performance rather than simple financial cost accounting. Performance-based regulation aims to replace competition in a regulated environment using financial rules and incentives that encourage a regulated company to achieve certain performance goals, while allowing the company significant discretion in determining how to achieve those goals.

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If a utility has superior processes and systems to achieve these goals, it can be expected to benefit financially. As a general rule, performance-based regulation focuses on service interruption measures such as SAIDI, CAIDI, and MAIFI customer responsiveness measures and the resolution of billing problems. Performance-based regulation is a relatively new area of regulation that needs to refine the rewards and penalties framework to ensure adequate investment in the assets, human capital, and technology necessary for robust transmission and distribution networks. Rules aimed at guaranteeing the quality of supply are therefore a key part of the incentive-based regulatory scheme. There is a general risk that network operators do not invest in their network or do not carry out other measures to maintain or improve the quality of supply, in order to save costs and boost profitability. To counter this situation, regulators can introduce incentive regulation of the quality of supply, including bonus and penalty systems. The quality of supply includes several parameters as, for instance, network reliability, network performance, service quality, and energy not supplied. Some examples of quality of supply parameters are given in the Chap. ▶ 5. The use of incentive-based regulation is increasing with a view to improving overall network efficiency.

3.3

Impact of Regulation for Asset Management

The development of formalized asset management approaches in TSO businesses can be considered as a consequence of the implementation of regulation. The regulatory drivers have focused on reduction of operational expenditures, and the economic justification of capital expenditures. In response, maintenance was optimized with the gradual implementation of appropriate policies, from preventive maintenance to condition-based maintenance. This development resulted in lower costs, as expected. It also led to a better appreciation of asset needs, in particular a method of classifying the different categories of assets in order to prioritize actions over the various asset classes. However, over the time, incremental cost reductions may have reached their limits. Obviously, unrestrained cost reduction cannot be applied without the potential to affect performance and quality of service. Efficiency has become the new driver of regulation. Thus, various forms of incentive regulation have been developed by many regulators. In addition, the methods applied in asset management have gradually moved from deterministic to probabilistic approaches. Thus, risk management has become essential for asset management, providing stronger justification for setting the priorities expected by regulation. Technology and innovation have also provided new facilities for better asset valuation. Asset decision-making is based not only on statistics but also on the actual conditions of the assets as provided by advanced sensors. Thus, asset management has benefited from continuous improvement of methods and tools for a better assessment of needs and in order to satisfy cost limitations set by regulation.

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Lastly, societal and public expectations are taking a more important place in the requirements set by the regulation, leading to new challenges for TSOs.

4

New Regulatory Initiatives

Over the past decade, in a few jurisdictions, regulators have recognized the need to include a more comprehensive regulatory approach. One of the pioneers in these efforts was the British regulator, the Office of Gas and Electricity Markets (OFGEM). The following paragraphs describe a few of their recent initiatives.

4.1

DNO Common Network Asset Indices Methodology Mandated by OFGEM`

OFGEM has implemented a regulation, which obliges Distribution Network Operators (DNO) to communicate information on the health and criticality of assets in order to provide the regulator with a measure of the risk of condition-based failure in distribution networks. In response, DNO’s in the UK have jointly developed a method, which is called the DNO Common Network Asset Indices Methodology. It has been reviewed and approved and is controlled by OFGEM so that all DNOs in the UK use a common method to produce the data that OFGEM requires. The declared objectives of OFGEM are to allow a transparent comparative analysis of network asset performance between DNOs over time, and to obtain a certain measure of risk reduction of assets over time resulting from asset interventions such as refurbishment or replacement. The results of the application of the methodology are to be provided to OFGEM in the form of risk matrices. DNOs are required for each asset in their networks to determine the probability of failure per annum and the monetized consequences of the failures of these assets and to combine these two measures to obtain risk measures. The consequences of a failure are assumed to include direct financial costs, as well as monetized safety, environmental and network performance costs. As a method of providing an asset risk measure transparently and consistently across all DNOs, this method is likely to meet OFGEM’s objectives. Likewise, the somewhat limited monetization of the consequences of failure, particularly for safety impacts approach is commendable. However, for any other purpose or from the point of view of asset managers who have to justify asset investments, the method is of limited use. The method was designed for application in the UK, is complicated to use manually, and is replete with factors for which no technical justification or reference is provided and which may or may not apply in other countries. The experience of the American US utilities with similar methods, but automated electronically, has shown that in practice they facilitate the application of

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subjective rather than objective factors, and may facilitate gaming to achieve desired results. The DNO Asset Indices Methodology is available as a document in the public domain at the OFGEM URL. The ownership of the methodology and its copyright is not defined in the documentation. However, because of the perceived credibility of the developers and based on its approval, and therefore, the implicit endorsement of OFGEM, other potential users may try to use the method for other purposes and applications and in other geographic regions. These potential users should keep in mind that the documentation does not claim that the method is applicable for purposes other than for the limited purposes stated in the documentation and for application in the specific region for which it was developed. Therefore, although the methods are an interesting and advanced example of a very quantitative approach, its use beyond the limited purposes for which it was developed and in regions other than the UK would require careful consideration and adjustment to local frameworks.

4.2

Transmission System Network Output Measures Fixed by OFGEM

Output measures are a fundamental element of the UK regulatory framework. Primary outputs such as safety, reliability and availability, environmental impact, connections, customer satisfaction and social obligations, monitor each Transmission Owner’s (TO) performance for the delivery of end services to consumers. Network Output Measures (NOMs) bring secondary outputs, which show that the TOs provide long-term value for money to consumers through a set of early warning measures or lead indicators. These assess the underlying performance of the transmission system. NOMs are designed to demonstrate that the TOs are targeting investment in the right areas to effectively manage network risks, ensuring that the TO will continue to deliver primary outputs and a network suitable for future use. Since investments in the network take place over the longer term, there would be a lag before underinvestment in assets has an impact on primary outputs. For example, if an asset is not replaced when necessary, it may take a while until the asset fails and affects the reliability of the network. Using the NOMs, licensees can identify the work required to manage their assets in order to provide a known level of network risk and thereby guarantee that they will maintain performance in future price control periods [OFGEM 2020]. The method as documented by Scottish Power is comparable with the DNO approach, while the method developed by National Grid Electricity Transmission (NGET) is a more rigorous risk-based approach. The NGNET’s approach is designed to provide estimates of overall asset risk for the principal assets in their existing network. It also includes a risk trading model, which is intended to provide overall asset risk vs. investment cost comparisons for alternative investment plans over a regulatory defined planning period.

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These initiatives by the UK regulator are important illustrations of the extent to which regulators are prepared to examine in detail risk management and asset investment processes used by utilities.

4.3

Benefit-Cost Analysis in the REV Context in New York

In 2014, the New York Power Authority implemented an initiative termed Reforming Energy Vision (REV). REV is a set of multiyear regulatory procedures and political initiatives launched in New York State in the USA. Its objective was to transform the way electricity is produced, bought, and sold in New York and to allow the integration of renewable energy generation and smart grid technologies on the electric grid [New York Department of Public Service]. The utilities, which are network operators, are motivated to use a proscribed Benefit-Cost Analysis (BCA) to justify their investments and to use the measures to respond to the REV. The BCA developed is the systematic quantification of the net present value (NPV) of a proposed action being considered. The specific action envisaged may be an investment, a contract, or a purchasing portfolio, alternative tariff designs, or alternative operating procedures. The BCAs performed for REV projects should: • Be transparent about assumptions, perspectives considered, sources, and methodologies. • List all benefits and costs borne by all parties, including localized impacts on host communities. • State which benefits and costs are not included or quantified in the overall BCA and why. • Not unnecessarily combine or conflate different benefits and costs. • Be designed to assess portfolios, rather than individual measures or investments, to allow the consideration of potential synergies and economies between resources or measures. • Reflect the expected level of Distribution Energy Resources (DER) penetration for the relevant time periods considered. • Be a full life-of-the-investment analysis and include a sensitivity analysis on key assumptions. • Assess the benefits and costs in comparison to a reasonable traditional or “business-as-usual” case rather than in isolation. • Strive to improve the granularity, that is, the locational and temporal specificity of the valuation of the benefit and cost components, especially for those at the distribution level. • Report results of the Societal Cost Test (SCT), Utility Cost Test (UCT), and Rate Impact Measure (RIM). • Allow for judgment, such that if investments do not pass cost tests based on included quantified benefits, a qualitative assessment of nonquantified benefits may be appropriate to inform approval.

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• Balance the interest in providing a stable investment environment for supporting the DER market, with the need to be sufficiently adaptive so that benefit and cost valuation does not become outdated and inaccurate. This BCA method is very similar to the CBA, Cost Benefit Analysis, used in Europe for the evaluation of transmission Investments. This is the subject of the next paragraph.

4.4

Projects of Common Interest Put in Place in Europe

In line with the previous case applied in New York State, the European Union (EU) implemented legislation to plan for and support Projects of Common Interest (PCI) to boost the energy transition and market integration in Europe [European Commission 2020]. The PCIs are key cross-border infrastructure projects that link the energy systems of EU countries. They are intended to help the EU achieve its energy policy and climate objectives. Any PCI project must have a significant impact on energy markets and market integration in at least two EU countries, boost competition on energy markets, and help the EU’s energy security by diversifying sources as well as contribute to the EU’s climate and energy goals by integrating renewables. According to European regulation, the European Network Transmission System Operators for electricity (ENTSO-E) has developed, and updated several times, a Cost-Benefit Analysis methodology for energy system-wide analysis to support the PCI selection process. The CBA methodology developed by ENTSO-E [ENTSO-E] computes a certain number of indicators, which are not all expressed as a monetary equivalent. These indicators include among others the following: • B1 – Socioeconomic welfare (SEW): This indicator represents the savings in production costs that are generated by the project due to the subsequent reduction in congestions. By congestion, this indicator also takes into account, firstly, the value of CO2 saving achieved, and secondly, the benefits derived from the reduction of the curtailment of renewable energy. • B5 – Power losses: This indicator gives the variation in costs due to the compensation for power losses, which can be attributed to the commissioning of the Interconnector project. Although this indicator can, in theory, be either positive (reduction in the cost of losses), or negative (increase in this cost), it represents most of the time a cost for the community. • B6 – Adequacy (resilience): This indicator seeks to evaluate the benefits in terms of security of supply, in other words, in terms of improving the capacity of the electricity system to meet demand in times of scarcity. The ENTSO-E introduces two indicators: – The expected energy not served (EENS, in MWh). – The additional adequacy margin (in MW) in those cases where the probability of unserved energy obtained in the simulations is zero.

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With respect to costs, the investment expenditure and the operating and maintenance costs of the projects have been taken into account. Some costs can also come from the impact of the commissioning of the PCI on the rest of the system (reinforcement, increase in required reserves, etc.). With the experience of CBA, the EU Agency for the Cooperation of the Energy Regulators (ACER) has extended the principle by establishing rules for cross-border cost allocation. In this case, the costs of infrastructure are shared by the beneficiary countries, not just the countries where the infrastructure is installed.

4.5

Proposal for Ontario Energy Board to Advance Innovation in Energy Sector

In the context of energy transition, Ontario Energy Board has identified actions the regulator could take to create an environment to support innovation that brings value to customers [Ontario Energy Board 2018]. Thus, the following broad actions have been identified for helping to support innovation in energy services: • Provide a transparent and level playing field by clarifying expectations and requirements regarding obligations between parties and toward customers • Remove disincentives to innovative solutions by changing how utilities are remunerated, and introducing more systematic methods of valuation and pricing • Encourage market-based solutions and customer choice by making more detailed and timely information available to sector participants • Embrace simplified regulation by adopting simple and timely ways to allow for experimentation. Uncertainty about regulatory reform can negatively impact the way utilities fare in capital markets and can also impact how attractive the energy sector is to investors. The focus of attention is mainly on innovation and regulatory reforms in the electricity distribution sector. However, the general actions identified may extend beyond the distribution of electricity, since opportunities for change arise in other areas such as storage, generation, and transmission of electricity.

4.6

Australian Energy Regulator (AER) Asset Management Industry Practice Application Note

The Australian National Electricity Rules (NER) require electric utilities to disclose information in their Annual Planning Reports and Regulatory Investment Tests relating to network asset retirement, renewal (that is, replacement or refurbishment), and de-rating. AER developed the Application Note in response to utility requests

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for clarity on how they might apply the NER requirements to their replacement expenditure planning of network assets. The Application Note provides detailed guidance and examples on how utilities could meet the NER requirements to demonstrate through risk-based business case analysis the prudence and efficiency of network asset retirement and de-rating decisions [AER 2019]. The Application Note itself is not binding, but it is intended to support utilities in considering relevant principles and approaches that could be applied under the guidelines. AER considers that the principles and approaches in this Application Note accord with good asset management and risk management practices, support sound asset retirement planning. Therefore, utilities are strongly motivated to use the AER methods when assessing alternative asset management investments because in the words of AER it “will aid in informing AER’s considerations.”

5

Summary

Utility businesses around the world have a range of different types of applicable regulation. The form of regulation depends on industry structure (e.g., vertically integrated, segregated, or deregulated) and the requirements of governments and their national industry regulators. The different requirements will continue to motivate and evolve a variety of asset management approaches around the world even if certain global trends are clearly visible. A review of the relevant CIGRE publications provides an overview of the evolution of the impact of regulations on asset management. Thus, in response to pressure on transmission costs, the first reaction was generally the deferment of maintenance and refurbishment actions. Investment priority remained the development of new infrastructure. Afterward, new methodologies such as asset management standardization (e.g., ISO 55000) and Enterprise Risk Management were developed to prioritize the needs and the actions within a fixed budget. With time, additional transmission needs occurred for the implementation of increased levels of renewable energy sources. These additional needs have led to new asset management approaches, new methods for better investment and expenditure assessment, and prioritization. In this regard, risk-based cost-benefit analysis methodologies are becoming increasingly popular, appropriate, and even needed and are used by utilities and regulators for justification and arbitration. The scenario methodology is also very useful in tackling the uncertainty of long-term investments such as for transmission infrastructure. A quick review of some current global regulatory practices and changing requirements confirms the above description. Thus, the use of risk management is confirmed for the selection of the priority actions within an organization. Cost-Benefit Analysis methods provide information about the impact and the benefits of action (e.g., investment in new infrastructure, or refurbishment of existing). The scenario methodology places the action in the perspective, facilitating comparison between different potential solutions.

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References AER, Industry practice application note Asset replacement planning, January 2019 Cigre Technical Brochure 327, Impact of regulatory environments on investment decision and transmission, 2007 Cigre Technical Brochure 474, Interface between System Operators and regulators, 2011 Cigre Technical Brochure 565, Regulatory incentives for capital Investments in electricity system, 2013 Cigre Technical Brochure 597, Transmission Risk Management, 2014 Cigre Technical Brochure 667, The Risk Management in evolving regulatory frameworks, 2016 Cigre Technical Brochure 692, Market price signals and regulatory frameworks for coordination of transmission Investments, 2017 Cigre Technical Brochure 715, The Future of reliability: definition of reliability in light of new developments in various devices and services which offer customers and system operators new levels of flexibility, 2018 Cigre Technical Brochure 726, Asset Management for distribution networks with high penetration of Distributed Energy sources, 2018 Cigre Technical Brochure 764, Expected impact on substation management from future grids, 2019 Cigre Technical Brochure 786, Investment decisions in a changing and uncertain environment, 2019 ENTSO-E Guideline for Cost Benefit Analysis of Grid Development Projects, September 2018 Ofgem, Distribution System Common Network Asset Indices Methodology, 2017 Ofgem, Revenue Incentives Innovation Output, Electricity Transmission Annual, Report 2018_2019, February 2020 Project of Common Interest, European Commission, Energy, 2020 Second Advisory Committee on Innovation, November 2018, Ontario Energy Board Staff white paper on Benefit-Cost Analysis in the reforming energy vision proceeding, July 2015, New York- Department of Public Service

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Asset Management Investment Planning Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Ge´rald Sanchis

Contents 1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 System Development Investment Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Traditional Drivers for System Development/Investment Planning . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Demand Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Generation Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 System and Customer Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Congestion Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 Integration of Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Asset Sustainment Investment Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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G. L. Ford (*) PowerNex Associates Inc., Toronto, ON, Canada e-mail: [email protected] G. Ancell Ancell Consulting Ltd., Wellington, New Zealand e-mail: [email protected] E. S. Hill Loma Consulting, Milwaukee, WI, USA e-mail: [email protected] J. Levine Hydro One (Canada), Toronto, ON, Canada e-mail: [email protected] C. Reali Independent Electricity System Operator, Toronto, ON, Canada e-mail: [email protected] E. Rijks TenneT, Arnhem, The Netherlands e-mail: [email protected] G. Sanchis RTE, Paris, France e-mail: [email protected] © Springer Nature Switzerland AG 2022 G. Ancell et al. (eds.), Power System Assets, CIGRE Green Books, https://doi.org/10.1007/978-3-030-85514-7_3

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5 Need for Integrated System Development and Sustainment Planning . . . . . . . . . . . . . . . . . . . . . . 5.1 Flattening of Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2 Increased Distributed Energy Resources (DER) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3 Electrification of Transportation and Proliferation of Heat Pumps . . . . . . . . . . . . . . . . . . . . 6 Processes and Methods for Integrated System Development and Sustainment Planning Capital Expenditure Versus Operating Expenditure Trade-Offs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1 Introduction to the Concept of “Right-Sizing” for Assets Reaching End of Life . . . . 7 Coordination of System Development Investments with Asset Sustainment Investments . . . 7.1 A Customer Value-Based Approach to System Development Investments at End of Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2 Global Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3 Challenges in Coordinating Transmission and Distribution Investments . . . . . . . . . . . . . 7.4 Challenges Due to Regulatory Framework on TSO and DSO Investments . . . . . . . . . . 7.5 Challenges in Comparing Investment in T&D Assets Versus Alternatives to Conventional Grid Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Considerations in the Light of Emerging Governmental Climate Initiatives and Technological Change in the Context of Conventional Grid Solutions . . . . . . . . . . . . . . . . 9 Summary and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

47 49 51 52 53 54 55 55 56 58 60 61 64 68 69

Abstract

While asset managers are dealing with operational and tactical investments in the near and medium terms (typically < 15 years), which are the focus of utility mangers and regulators, such asset investments have very long-term expected operational lives (40–50 years or more). For example, as assets approach end of life, the system need could be very different from what it was when the assets were new, 50 years, or more ago; so like-for-like replacement of such assets may be inappropriate. Therefore, there is a need to take a longer-term systems perspective which is the challenge of systems investment planners. In recent decades, this role has become increasingly complex. The transition from largely vertically integrated utilities where planning was well organized over to disorganized configurations of independent market entities (generation, transmission, distribution and independent system, and market operators) has made investment planning complex. More recently, the complexity has been increased by uncertainty in governmental initiatives related to climate change such as the net zero by 2050 which will have profound impacts on system development planning for electric power systems. This chapter focuses on these issues and discusses the relationships between asset sustainment investment planning and system development investment planning and the need to coordinate these two functions. It explores processes and methods for integrated development and sustainment investment planning, including trade-offs associated with capital expenditure and operating expenditure, the need to “right-size” investments, the different approaches required for considering Transmission System Operator (TSO) investments versus TSO-Distribution System Operator (DSO) coordinated investments. As well it explores the place for considering emerging technologies as opposed to conventional grid solutions for addressing asset management problems.

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Introduction

Power systems around the world include a critical mass of assets that are reaching the end of their useful life (EoL). The replacement of power system assets is an important decision; it is one that asks the question “do we think that this asset will be utilized in the same way over the next 50+ years as it was in the past or is a fundamentally different approach required to address the challenges of our future power systems?” If we reflect on what the drivers of power system expansion were at the time when present EoL assets were commissioned, could planners and engineers have known what our power systems requirements would be like today? When an asset reaches its end of useful life, it presents a unique opportunity – should it be replaced like-for-like, upgraded, consolidated; should an innovative or demand side facility take its place instead? This chapter addresses these questions and more, and provides readers with guidance on approaches to coordinate system development planning with asset sustainment investment planning. In particular, this chapter achieves the following: • Defines system development investment planning in the context of an existing asset base and emerging system needs, and the opportunities presented by new and emerging technologies • Defines Sustainment Investment Planning in the context of addressing and managing existing asset end of useful life • Discusses why integrated system development and sustainment investment planning is required • Explores processes and methods for integrated development and sustainment investment planning, including trade-offs associated with capital expenditure and operating expenditure, the need to “right-size” investments, the different approaches required for considering Transmission System Operator (TSO) investments versus TSO-Distribution System Operator (DSO) coordinated investments • Explores the place for considering emerging technologies as opposed to conventional grid solutions for addressing asset management problems

2

System Development Investment Planning

For the purposes of this chapter System Development Investment Planning refers to the development of new system facilities to be integrated with the power system for the purpose of increasing the system’s capacity, reliability, or market efficiency. Such investment is normally needed to meet the following drivers: • Growth in electrical demand • Interconnecting new generation or loads

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• Maintaining system and customer reliability, reducing Energy Not Supplied (ENS) • Reducing system congestion, and/or • Integrating electricity markets The key distinction with respect to System Development Planning in this context is that it is for the purpose of optimizing the power system’s capability, reliability, and market efficiency. The optimization ensures future demands on the power system are met, new loads and generation are connected, reliability is maintained at an appropriate level, and congestion on the grid is reduced where economic to do so. The related capital costs for System Development investment must be justified on a business case, which considers the technically feasible options and a new or modified revenue stream. System Development Planning is more concerned with Capital Expenses (CAPEX) rather than Operating Expenses (OPEX) although lifetime operating expenses of new assets are typically considered in business cases.

3

Traditional Drivers for System Development/Investment Planning

Before one can discuss the need for integrated Investment and Sustainment Planning, traditional drivers for System Development Planning must be understood.

3.1

Demand Growth

Growth in electrical demand is the primary traditional driver for System Development Planning. Growth in electrical demand can generally require new transformer stations to connect new demand to the transmission network (“new load connections”). New load connections can generally result in increased loading of existing transmission system facilities. If this increased loading results in system performance criteria that are used for System Development Planning to be violated, additional reinforcements to the transmission system are required. These reinforcements include: • • • •

Reinforcement of existing transmission lines Installation of new transmission lines Installation of new reactive power compensation devices New switching stations, among other new facilities

Additional system reinforcements are normally justified through least-cost planning principles to minimize price increases to customers and maximize the utility’s rate of return. The recovery of costs associated with new system facilities and increased capacity driven by new load connections are dependent on the individual jurisdiction’s regulatory framework. Normally the new revenue stream associated with the additional

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demand growth is used to justify the business case associated with the new system facilities. If the new revenue stream from the additional demand growth is insufficient to meet the TSO’s revenue requirement, other mechanisms are needed to maintain the TSO’s financial integrity. This may include a capital contribution from an individual customer as part of a connection cost-recovery agreement, an increase in transmission tariffs, variance accounts, among other financial mechanisms.

3.2

Generation Interconnection

Growth in electrical demand is often complemented by requirements for new generation resources. Decarbonization policies such as “Net Zero 2050” may also drive the need for new renewable generation connections to the transmission system. The new renewable generation can be mature technologies such as hydropower generation or new technologies such as inverter-connected generation such as solar or wind generation. New technologies have different performance capabilities, which need to be reflected in interconnection standards and grid codes. These requirements pertain to low-voltage ride-through capability, remaining connected during transient underfrequency and over-frequency excursions, oscillatory damping, reactive power generation and absorption, minimum connection arrangements, among other things. Additional system reinforcements that are triggered from generator connection requirements are often the cost-responsibility of the generator. The generator normally accounts for such costs in their business case and recovers those costs through its payments for energy, capacity, regulation services and/or any other services provided through bilateral agreements, and/or market mechanisms. Decarbonization policies may also include provisions such that renewable generators are additionally compensated through subsidies, feed-in tariffs, or other renewable energy incentive payments.

3.3

System and Customer Reliability

TSOs are required to meet system reliability performance in accordance with reliability standards and customer supply quality in accordance with customer agreements and/or regulatory requirements. Some TSOs have performance incentives for meeting regulatory measures such as energy not supplied or customer satisfaction. Additional system reinforcements that are triggered due to a need to meet system reliability standards are normally justified on a least-cost planning approach and justified to a regulator or utility board. The costs associated with system reinforcements for system reliability are normally considered nondiscretionary expenditures in license, codified, or legislative requirements. The increased revenue requirements associated with nondiscretionary costs are normally recovered from all customers or a group of customers through increases in the transmission network tariff. Specific cost-recovery mechanisms will obviously vary by jurisdiction.

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Congestion Management

Most mature electricity markets have to address power system constraints, such as transfer limits for a transmission circuit of group of transmission circuits (“transmission interface”). A constraint can limit the amount of generation that is able to connect in an area. Some constraints will cause the use of more expensive generation even though there is excess lower cost generation available in the constrained area. The traditional way electricity markets address transmission limit constraints is through some form of locational pricing. When transmission limit constraints are binding, locational pricing will result in relatively higher marginal price for energy on the receiving side of the constrained transmission interface, and a relatively lower marginal price for energy on the sending side of the constrained transmission interface. This price differential (sometimes referred to as “congestion rent”) is the economic consequence of transmission congestion. If this price differential is substantial and forecasted to persist or become exacerbated, it may trigger the need for additional system reinforcements through the System Development Planning process. Normally system reinforcements are justifiable to manage congestion if the discounted cash flow analysis pertaining to the net-present benefit of forecasted reduction in congestion rents is greater than the net-present cost of the transmission reinforcement.

3.5

Integration of Markets

The interconnection of two previously unconnected electricity markets potentially provides improved reliability, resilience, and access to lower cost electricity. This is particularly evident in parts of the world whereby greater geographical proximity to neighboring markets exist, such as in Europe. Business case models associated with transmission reinforcements for greater market integration can vary greatly. The variety of business case models associated with transmission reinforcements is currently being explored by CIGRE Working Group C1.33 “Interface & Allocation Issues” in multiparty and/or cross-jurisdiction power infrastructures projects. The most common and simple business model associated with market integration is the merchant transmission business model, whereby the merchant transmission owner auctions rights to use its transmission line to access a neighboring market.

4

Asset Sustainment Investment Planning

Assets age and deteriorate under the influence of loading and environmental stresses. Materials deteriorate becoming weaker and less capable of withstanding these stresses. Chapter ▶ 4 describes these aging processes as they apply to key transmission assets such as transformers, switchgear, and overhead and underground transmission lines and discusses asset end-of life and methods for managing it. Some aging processes take place over long periods and it is possible that the asset will be

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replaced or upgraded for other reasons while still being capable of meeting performance specifications. Asset sustainment investment planning refers to those activities that enable the continued reliable and safe operation of the existing power system assets or which extend the normally expected service lives of existing assets. These activities include the consideration of more versus less maintenance and repairs, refurbishments, replacements, and other options for existing assets based on the following considerations: • Asset condition • Asset service life • Health and safety, and other corporate KPI risks associated with in-service failures • Compliance requirements • Reductions of losses, and • Other emerging issues The context of sustainment planning is fundamentally different from system development planning in that the purpose of asset sustainment planning is not to increase system capacity (although that may be an unintended result) but to maintain the existing assets’ reliability. This includes routine maintenance activities for the existing system assets so that they achieve their planned economic life. Most investment in asset sustainment is considered to be Operating Expenses. Chapter ▶ 6 describes operational asset management, which includes actions and investment planning needed to sustain assets in the current year and in the near-term. This includes on-going asset condition assessment, asset performance data and monitoring, and decision-making to support near-term investment prioritization typically based on qualitative risk-based health index/criticality assessments. Asset sustainment investment options and tactics in the medium- to longerterms is the subject of Chap. ▶ 7. This focuses on managing populations of aging assets with adverse demographic distributions to determine optimal tactics for managing risk and investment levels, and business case analysis methods applied to a range of asset sustainment investment options and trade-offs. Asset sustainment planning includes the options of refurbishing assets, which extend asset expected lives, uprating assets to achieve higher capacities, and ultimately replacing assets that have reached end of life and which continue to be essential for the system. These types of sustainment investments are included in the CAPEX category.

5

Need for Integrated System Development and Sustainment Planning

Power systems of developed nations around the world underwent a significant expansion post World War 2, which has resulted in adverse demographic distributions such as described in TB 176 and illustrated below.

48

G. L. Ford et al. Mean and Standard Deviation of Asset Life Estimates 1600 1400

Population

1200 1000 800 600 400 200 0 0 to 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 5 Age in 1998 (Years)

Adverse demographic distribution (the Bow Wave) as described in TB 176 [CIGRE WG37-27]

This has resulted in a substantial and immediate increase in asset end-of-life planning. The replacement of assets at the end of their useful life implies that capital expenditures are required, however without any associated growth in revenue, the business case to support end-of-life planning becomes uniquely challenging. Compounding this challenge are environmental and social drivers that are transforming the ways that the world uses electricity. CIGRE has recognized this paradigm shift, which includes the following aspects: • Flattening of consumption in the near-term due to population stabilization and increased energy efficiency of end-use loads • Net zero 2050 and other environmental initiatives aimed at slowing global warming, which will lead to: – Increased distributed energy resources (DER), – The prospect for electrification of transportation – The prospect for the proliferation of heat pumps – Increased desire for market access, and – Increased need for system resiliency This paradigm shift requires system development planners to think differently. Addressing both System Development needs and Sustainment (asset end-of-life) needs must be thought about in an integrated way in order to ensure continued affordability, reliability, and sustainability of electricity supply.

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A key factor in System Development Investment Planning is Demand forecasting. CIGRE Working Group C1.32 produced a technical brochure (TB 670) on establishing best practice approaches for developing credible electricity demand and energy forecasts for network planning in 2016. The Working Group carried out a survey of forecasting practices. Most forecasting software is developed in-house. One of the findings of the Working Group was that demand forecasting methodologies were frequently revised suggesting best practice is not widely agreed. TB 670 indicates the most important influences needing to be incorporated into load forecasting in the next 10 years are: • Penetration of Renewable Energy Sources (RES) • Demand side response management • Storage and electric vehicles These influences are discussed in more detail later in the Chapter.

5.1

Flattening of Consumption

Although one of the primary traditional drivers for System Development Planning is demand growth, developed economies have been experiencing a recent flattening of consumption. This is clearly illustrated below. Total electricity consumption OECD Total 1990 - 2016 12 500

TWh

10 000 7500 5000 2500 0 1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

2016

IEA World Energy Balances 2018

Flattening of electrical energy consumption from 1990 to 2016 [OECD]

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The flattening of consumption in developed economies can be attributable to a number of factors; most notably stabilization of population, globalization of productive capacity, and increased efficiency of end-use loads. In general, the flattening of consumption results in downward pressure on throughput in transmission and distribution systems. As noted below, although downward pressure may result from flattening of demand, the net effect is convoluted from a number of other drivers. While the OECD data illustrates a clear flattening of electrical system loads over the past two decades, asset managers need to consider what may or will likely happen to load levels over the prospective decades ahead. Environmental, regulatory, financial, and business initiatives can have significant influence on load projections over longer-term planning periods. For example, current “net zero by 2050” government policies can and likely will have significant impact on electric system load as illustrated from the National Grid ESO study in the UK, Future Energy Scenarios 2020 [National Grid ESO]. The projection illustrates the decline in the UK system load over the past decade; but in view of changes in the sources of energy that would be brought about by a net zero by 2050 strategy, the UK electrical system load is projected to significantly increase over the next three decades. Electricity peak demand (including losses) 100 90

GW 70 60 50 2010

2015

2020

2025

2030

2035

History

Consumer Transformation

Leading the way

Steady Progression

2040

2045

System Transformation

2050

FES2020 / System view / Introduction 57

80

Electrical load projections in the UK under various scenarios to achieve net zero carbon by 2050. [National Grid ESO]

In the USA, government strategy appears to be trending toward a net zero approach; but system load growth is expected to be moderated by increased demand

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management efficiency programs and increased behind the meter solar as illustrated below.

©PJM 15-year load forecast illustrating the impacts of solar and efficiency programs on load growth in the absence of a net zero government strategy

5.2

Increased Distributed Energy Resources (DER)

The amount of DER generation on distribution systems has increased rapidly in recent years. This may be inferred from the following figures which illustrate growth in Solar PV electricity generation and in Wind electricity generation in Organization for Economic Co-operation and Development (OECD) countries. Solar PV electricity generation OECD Total 1990 - 2016 250 000

GWh

200 000 150 000 100 000 50 000 0 1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

2016

IEA Electricity Information 2018

Growth in Solar PV electricity generation

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G. L. Ford et al. Wind electricity generation OECD Total 1990 - 2016 700 000 600 000

GWh

500 000 400 000 300 000 200 000 100 000 0 1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

2016

IEA Electricity Information 2018

Growth in Wind-based electricity generation

Although Solar PV and Wind generation are not exclusively connected on distribution systems, large portions do exist on distribution systems and the rapid growth can provide a sufficient indicator for the increase in DER. Growth in DER can impact the Transmission system and Distribution system in a number of ways, most notably: reduced peak loading and energy transfer on transmission and distribution networks, changes in power flows including reverse power flows, and increased voltages and changes in fault level. These impacts will require transmission and distribution owners to alter operational and equipment specification polices as discussed in TB 726 Asset Management for distribution Networks with High Penetration of Distributed Energy Resources [WG C6.27]. With a high penetration of DERs, and the trends from distribution network operator (DNO) and distribution system operators (DSO), the development of a holistic asset management strategy is crucial, yet complex. In view of market players being independent profit-oriented entities, sharing of development plans going forward is difficult. Power systems are planned and built with a long-term perspective. However, the future is uncertain, and unpredictable things happen. TB 726 provides useful guidance in the use of scenarios to evaluate possible future outcomes including an example for using scenarios to understand an unpredictable future for asset management of distribution networks by explaining a real case in Norway.

5.3

Electrification of Transportation and Proliferation of Heat Pumps

The number of Electric Vehicles (EVs) is swiftly increasing in many parts of the world. The charging of EVs brings both challenges and opportunities for transmission and distribution systems. EV charging can increase peak electricity demands, which can lead to transformers and cables becoming overloaded and voltages becoming unacceptably low. The developing capability of EVs to inject electricity back into the power system (e.g., Vehicle to Grid) provides another tool for managing the operation of the power system both at the transmission and distribution levels. Heat pumps provide an alternative and very energy-efficient form of heating to fossil fuel-based heating systems; if powered with carbon free electricity, e.g., from

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renewable energy sources, the heating becomes CO2-neutral. The number of heat pumps is likely to increase significantly as nations pursue decarbonization policies. Large numbers of heat pumps can cause problems on distribution networks. The starting current of the heat pump compressor motor is higher than the normal running current. There are also transient effects when heat pumps switch on and off. Heat pumps also can provide benefits to the power system. The motor inertia of heat pumps helps stabilize the power system and heat pumps can be used in demand response programs.

6

Processes and Methods for Integrated System Development and Sustainment Planning Capital Expenditure Versus Operating Expenditure Trade-Offs

Some assets in transmission systems, as in the ship of Theseus paradox1 are refurbishable. For example large power transformers age in service and as they do so moisture is released from the paper insulation systems. The moisture increases losses and weakens the dielectric withstand of the transformer. Routine diagnostic testing of the oil reveals the increasing moisture content. Transformer life is directly related to the loading and the moisture and oxygen levels in the transformer. The higher these levels, the shorter the transformer life. At some point typically near mid-life, asset managers may decide that investing in refurbishment in the form of an extended outage to treat the transformer to remove moisture and oxygen is justified to extend its useful life. At the same time they may decide to refurbish or replace tap changers, bushings, coolers gaskets, seals, and so on. Similarly, overhead transmission lines age through corrosion of towers and conductors, concrete foundations crack, and hardware wears out. All of these components can be repaired or replaced in line refurbishment programs that will allow extending the lines life almost indefinitely. Repairs can and are often done on a piecemeal basis and are included in OPEX budgets, whereas refurbishment of a whole line involving conductor replacement, tower painting, and so on, would be considered to extend the life of the line and increase its value and the cost is included under CAPEX budgets. In 2016, Transpower (the TSO in New Zealand) recognized that although the majority of their disconnectors are of high quality durable design, compared with international peers, the disconnectors were experiencing consistently poor operational performance. Transpower’s CAPEX forecasts included $12.5 million NZD for capital replacements of aging disconnectors, but an age-based disconnector and earth switch replacement strategy couldn’t be supported. Transpower completed an asset management investigation to explore an alternative approach that could boost asset performance while deferring or avoiding capital expenditure. They investigated whether the life of certain disconnectors and earth switches could have their life extended by improving maintenance practices. The ship of Theseus paradox dates from the first century. The paradox poses the question; if a ship is made of 100 pieces of wood and over time each old piece is replaced by a new piece of wood, is it still Theseus’ old ship?

1

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Transpower found that vitally important knowledge about the maintenance of these disconnectors had never been documented, and that expert level knowledge about disconnectors was held by a small number of senior service providers who in many cases were approaching retirement. Transpower focused on capturing and documenting this information and worked to develop new ways of delivering training to roll out new maintenance practice standards. Transpower systematically worked through the options and demonstrated how they could effectively trade off CAPEX with OPEX to realize long-term savings. The new strategy resulted in an increase in OPEX, but this is dwarfed by the CAPEX savings and overall $6 million NZD in savings was achieved. Further details on this are provided in ▶ Part 2 – Case Studies. Transformers with projected peak loadings somewhat above their ratings provide an asset management challenge for which there may be several optional solutions, as follows. • Accept the reduction in service life. A calculation of the loss-of-life that would be incurred for running through peaks will show if the economic value of the loss in transformer life was high enough to justify consideration of other options. • Implement a real-time dynamic monitoring system to manage the loading through system peaks to avoid exceeding the ratings. This system could be an automatic load shedding scheme or direct load control. • Another option in such cases is to extend the life of the transformer by several years by reducing loading during peak load periods. This could be accomplished by transferring load to adjacent transformer stations at peak load periods. Typically, in urban and suburban areas significant load transfer capacity exists between transformer stations at the distribution level. This life extension option would result in incurring incremental annual O&M costs due to increased operational costs to achieve the load transfer, potential increases in losses, and generally increased monitoring and maintenance expected on an older transformer unit. Other considerations in evaluating such options include ensuring public and employee safety is not compromised and investigating the potential impact on reliability performance. Another Capital O&M trade-off can occur when more cost effective and reliable technology becomes available. Modern electronic protection and control (P&C) technology that has increased and desirable new functionality requiring significantly less maintenance, could make older P&C technology economically obsolete. Thus, the replacement of conventional equipment prior to its normal economic end of life could be justified.

6.1

Introduction to the Concept of “Right-Sizing” for Assets Reaching End of Life

Right-sizing is defined as sizing a facility (an asset or several connected assets) appropriately for the need, recognizing that the original need for the facility may

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have been very different and that its rating needs to be coordinated with the system of assets in which it operates. Assets currently reaching end of life typically had their original need planned over 50 years ago. Planning and investing in assets with expected lives spanning five or more decades requires consideration of the tremendous amount of change that may take place in the power system over the decades ahead. These changes may include, but are not limited to, the establishment of new load centers, the retirement of specific generation facilities, economic transformation from traditional industrial-age business (mining, steel, manufacturing) to communication and information-age business such as cloud data centers, bit-coin operations, incorporation of new utility standards (e.g., in light of the need for system resiliency), and the evolution of new power system technologies such as distributed renewable generation, battery and other forms of energy storage, etc. The magnitude of technological changes that can take place, the uncertainties of the economy, and demand on the power system over the life of a specific asset lead to a very difficult question: is the purpose and need for this particular asset waning, steady, or increasing? The nature of system development is that investments to the system are made incrementally such that assets continue to serve a purpose, although possibly secondary to the purpose for which they were originally installed. This leads into the question of what is the system requirement now and going forward for the asset to the end of its economic life. Is the current asset rated correctly, i.e., the “right-size” should it be replaced like-for-like, or should it be replaced with and asset with increased capability, or consolidated capability? Facility end-of-life provides an opportunity to review current needs in view of developments of the last 50 years and new technologies for meeting those needs. Options include increased capacity, or consolidated facilities and providing incremental economic value to electricity ratepayers. Assets in the form of transmission rights-of-way or substation or generation station sites need to be reviewed to consider future opportunities such as repurposing to allow new interconnections and applications.

7

Coordination of System Development Investments with Asset Sustainment Investments

7.1

A Customer Value-Based Approach to System Development Investments at End of Life

The following section describes an approach for considering the potential for system development investments at the point when transmission or distribution assets reach the end of their useful life. This approach considers maximizing value to the customer or ratepayer as the objective, as opposed to shareholder profit of the transmission utility, and of course bound by the constraint of meeting reliability standards or criteria.

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This idealist approach consists of the following primary steps: 1. Identify assets that are expected to reach the end of their useful life with sufficient lead-time within the planning horizon (through normal financial, age, and condition assessments as deemed to be best practice by the utility to establish expected service life). 2. Identify any assets that are in close electrical proximity or are within the same portions of the transmission system serving common or dependent functions that will reach their expected service life within 5 and up to 10 years from when the asset from (1) has been deemed end of life. 3. Consider the base case system as if the assets from (1) and (2) are retired. 4. Perform a planning needs study on the base case referred to in (3), identifying all system needs as if the assets did not exist, such as: (a) Load connection need (b) Generation connection need (c) Network performance need (thermal capacity, voltage performance, stability performance, etc.) (d) Economic or market efficiency need 5. Perform a planning options analysis in order to meet the needs identified in (4), including the consideration of replacing the assets considered in (1) and (2) likefor-like, as well as other potential options that may have emerged, including Distributed Energy Resources. 6. Perform a preferred option selection based on the utility, planning authority, or regulator’s decision-making criteria (e.g., reliability, least-cost, feasibility, environmental impact, societal impact, and/or others). Other considerations include consideration of land-usage, changes in voltage class, and addition of capacity. From a practical perspective, various forms of this process have been implemented depending on institutional factors such as whether the utility is vertically integrated or not, the business model of the utility, the planning framework within the jurisdiction (e.g., is the planning process led by an Independent System Operator?), the regulatory framework governing the jurisdiction, among others.

7.2

Global Developments

Utilities develop planning processes in the context of their regulatory and business environments. Processes in the UK developed by National Grid Electricity Transmission and in Canada by Hydro One are described in Chap. ▶ 7. PJM in the USA is a large regional transmission operator (RTO). It carries out an ongoing regional planning process, which is continually reviewed and updated in a 24-month and 18-month cycle and illustrated below [PJM].

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Cycle 2 Yr -1 S O N D J

Cycle 1 Yr 0 F M A M J J A S O N D J

Yr +1 Yr +2 F M A M J J A S O N D J F

Develop assumptions Reliability criteria analysis for years 5 - 15

18-month cycle

Identify and evaluate solution options Review with TEAC and approval by the PJM Board

Develop assumptions and build Year 8 base case Perform criteria analysis for years 8 - 15

24-month cycle

Perform reliability and market efficiency analysis for Year 8 -15

Identify proposed solutions Develop assumptions and build Year 7 base case Re-tool of analysis for years 7 - 15 including solution options

Independent consultant reviews of buildability Adjustments to solution options by PJM based on analysis Develop assumptions 18-month cycle Reliability criteria analysis for years 5 - 15 Identify and evaluate solution options Review with TEAC and approval by the PJM Board

START

Review Proposals

Does Project Pass B/C?

Perform B/C YES

Does project require additional upgrades?

YES

NO Does Reliability & Constructability Analysis require changes?

NO FINISH

Project Recommended

NO

YES *Other factors considered such as PJM Overall Production Cost, load Payments, and congestion

Does project reduce or fix congestion driver?

NO

YES

YES

Does project cause unacceptable congestion?

Is the project competitive?

NO Project Not Recommended

YES

Project Not Recommended

YES

NO Sensitivity Analysis Other Factors considered*

©PJM 24-/18-month regional planning cycle and project selection process

NO

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This figure also illustrates PJM’s process for project benefit/cost (B/C) evaluation and project selection. In 2006, PJM expanded the transmission planning process to extend the horizon for consideration of expansion or enhancement projects to 15 years. This enabled planning to anticipate longer lead-time transmission needs on a timelier basis. A baseline reliability analysis underlies PJM’s planning analyses and recommendations. PJM’s 15-year planning review now yields a regional plan that encompasses the following: • Baseline reliability upgrades • Operational Performance issue-driven upgrades (load flow, short-circuit and system voltage, and angular stability issues) • Market efficiency-driven upgrades (for example, transmission congestion issues) • FERC projects, and public policy requirements • Supplemental Projects by a Transmission Owner, which include asset sustainment projects addressing end-of-life management of existing facilities A Case study in Chap. ▶ 21 of Part 2 describes PJM’s Probabilistic Risk Assessment for Spare Transformer Planning, which is derived from this process based on reliability and market efficiency upgrades. Clearly, system reliability, efficient operations, and cost-effective asset management investment decisionmaking are key PJM concerns. The PJM case study describes analysis supporting decisions to invest in spare transformers and where they should be located in the network to obtain significant benefits in terms of reduced transmission congestion charges in the event of transformer in-service failure. In New Zealand, Transpower (TSO) and the distribution companies are required to publish and regularly update their Asset Management Plans. The Asset Management Plans include both system development planning and sustainment planning. Forecasts of capital and operating expenditure for the next 10 years are included. The planning cycles are determined to a large extent by the 5-year regulatory periods in New Zealand. Transpower and the distribution companies are subject to pricequality regulation. The maximum amount of revenue they can earn over 5-year periods (e.g., 2020–2025) and the minimum service quality targets are set at the start of the 5-year period. Large value transmission projects greater than NZD 20 M are approved separately as required.

7.3

Challenges in Coordinating Transmission and Distribution Investments

There can be challenges in coordinating transmission and distribution investments when investments are made by different parties with different objectives, budgetary constraints, and levels of access to capital. Transmission and distribution commonly are the responsibilities of different owners. Even in vertically integrated power

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systems, decisions on transmission investments and distribution investments may be made by different divisions who may have different objectives. In some jurisdictions, the regulatory framework of transmission investments is different from that of distribution investments. Some regulators require transmission investment proposals to consider transmission alternative options. An example of a transmission alternative is where a transmission business needs to install larger transformers to meet increasing demand from a distribution company. One important factor in transmission and distribution investment decisionmaking is the forecast of future demand. Transmission owners will often use historical demand at transmission–distribution interface as the basis of forecasting. Distribution owners may have a quite different view of future demand at the same transmission–distribution interface, based on their local knowledge. Distribution operators will know of large loads that will connect or disconnect to the distribution network, their plans to shift load from one transmission–distribution interface to another and their load control capability to manage peak demands. It is valuable for network planners at the transmission and distribution businesses to meet on a regular basis to discuss load forecasting. Transmission businesses and distribution businesses may have different views of reliability. Transmission businesses may require electricity supply to be maintained during certain asset outages. Distribution businesses may accept a lower reliability (e.g., interruptions during asset outages) or short-term overloading of assets particularly in instances where the distribution business will have to pay for the additional assets required to provide the higher reliability. Based on these considerations, there may be a number of options for companies considering whether to address investments in distribution or transmission. There are sometimes distribution-based options for transmission problems as well as transmission-based options. Distribution businesses can reduce loading on transmission assets by shifting load to other substations in their distribution area or by improving power factor at the transmission–distribution interface. Likewise, there are sometimes transmission-based options for distribution problems. For example, high fault levels on the distribution network that exceed the fault ratings of distribution equipment can be reduced by replacing existing transmission substation transformers with transformers of higher impedance or the use of current limiting reactors. The party responsible for preparing business cases for transmission or distribution investments can have weak or strong incentives to consider distribution-based options as well as transmission-based option. The incentive can be of a financial nature such as getting another party to pay to fix the problem or a requirement to get the new investment included in a utilities rate base. The business case approval process may be different for transmission and distribution investments. One or the other approval processes may require less effort and be the preferred way of proceeding. The difference in approval process can arise from different regulatory regimes applying for transmission and distribution or where transmission and distribution are separate entities with different business

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processes. Separate transmission and distribution entities may have quite different perspectives on the nature of planning problems and the priority to resolve them.

7.4

Challenges Due to Regulatory Framework on TSO and DSO Investments

Regulation of TSO and DSO investments is commonplace internationally. Regulatory frameworks typically regulate price and quality. Transmission and distribution businesses are allowed to earn up to certain rate of return while meeting performance targets. Performance incentive schemes are also employed, which reward superior performance and punish inferior performance. Regulators determine the revenue allowed to be earned by transmission and distribution businesses taking into account forecast capital expenses and operating expenses, and allowances for return on existing asset investments and asset depreciation. However, in the context of ensuring sound asset management decisions are made in the interest of customers or ratepayers, many regulatory frameworks present disincentives to sound practices when equipment reaches the end of its useful life. For example, if an asset that was installed over 50 years ago is no longer utilized to the extent it was originally planned, and it is objectively more efficient to retire the asset without replacement, it would result in an overall reduction in the transmission or distribution company’s regulated asset base, reducing its overall cost-recovery requirements and reducing its profit based on a regulated rate of return. Regulatory frameworks need to ensure that their methods for incenting utilities to act costeffectively in the interest of customers and ratepayers result in appropriate decisions that do not lead to uneconomic outcomes. In contrast, when equipment reaches the end of its useful life and it is heavily utilized and is projected to increase in utilization; existing regulatory frameworks generally incentivize utility companies appropriately to uprate or increase the class of the equipment. Although the logic holds from the paragraph above, it works in the opposite way – as uprating or increasing the class of the equipment is also more costly and therefore increases the utility’s revenue requirement for cost-recovery, it would also increase their profits based on a regulated rate of return on its prudently incurred costs. In 2014, the Senate of the Parliament of Australia (Government of Australia) started an inquiry into the performance and management of electricity companies. Electricity prices in Australia were increasing at considerable rate at a time when demand growth was forecast to be flat. The price increases lead to accusations of excessive investment in network assets. Institutional arrangements and regulatory design were touted as possible causes. In 2017, The Australian Consumer and Competition Commission (ACCC) held an inquiry into the supply of retail electricity and the competitiveness of retail electricity prices. The following illustrates the increase in regulatory asset base of network businesses in Australian states.

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Increases in Regulatory Asset Base from Figure D of [ACCC]

The ACCC recommended write-downs of regulated asset bases or rebates to consumers.

7.5

Challenges in Comparing Investment in T&D Assets Versus Alternatives to Conventional Grid Solutions

Alternatives to transmission-based options and distribution-based investments such as new generating plant, DER and demand response are sometimes difficult to compare directly with transmission-based options and/or distribution-based options. Generation in the right location can be used to defer the need to increase transmission or distribution capacity. The generating plant might have a lower availability than transmission or distribution circuits, which may cause a reduction in reliability. Asset failures may have markedly different repair and failure times. The transmission or distribution business may need a performance contract with the owner of the generating plant. The transmission or distribution business loses visibility to some extent of the assets providing a service for the benefit of the transmission or distribution businesses’ customers. This loss of visibility will reduce confidence in the value of the transmission or distribution alternative.

7.5.1 Background Over the years, utilities have invested in assets and increased the capacity of their systems to meet the ever-increasing loading. However, demand is increasingly difficult to manage or predict and a number of alternate means of managing load are entering the market. These other means can involve more efficient loads demand management, generation behind the meter, among others. With the increasing difficulty of building new lines and substations, TSOs strive to make the best use of their existing assets and improve the sustainability of new designs and components installed on the grid. R&D and innovations such as smart technology play key roles in the future development of the grid. These fit into two

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major categories: Distributed Energy Resources, demand response, and direct load control, batteries and Smart Grid applications, and other grid innovations. These include the following: • Increasing the power-flow capability of the existing transmission system must recognize that the system needs to be secure at all times under reliability-based criteria. Operating near the real maximum circuit ampacity can be achieved by monitoring weather conditions and utilizing Dynamic Line Ratings (DLRs) for overhead lines (OHLs). • Underground-cable designs with embedded optical fibers that sense conductor temperatures can be used to establish ratings and monitor the line’s conditions, which reduce the number of outages. • Power flow modification using adaptive and flexible electronic devices (Smart Modules). • Large-scale battery energy storage at the sub-transmission level to reduce potential local congestion, particularly excess flows that result from local renewable generation.

7.5.2 Distributed Energy Resources Alternatives to transmission-based options and distribution-based investments such as new generating plant, DER, and demand response are sometimes difficult to compare directly with transmission-based options and distribution-based options. Generation in the right location can be used to defer the need to increase transmission or distribution capacity. The generating plant might have a lower availability than transmission or distribution circuits, which may cause a reduction in reliability. Asset failures may have markedly different repair and failure times. The emergence of new technologies such as distributed battery storage is a new area for transmission and distribution businesses. Distributed battery storage is both beneficial and problematic for transmission and distribution businesses. Distributed batteries can reduce the loading on distribution and transmission networks at peak times and reduce reverse power flows when other DER is generating. Distributed batteries can make peak loading and reserve power flow issues worse. Transmission and distribution businesses will increasingly need to engage with aggregator businesses, which represent large numbers of small- and medium-sized customers to facilitate coordination of large amounts of demand and DER. 7.5.3 Demand Response Utilities can also influence load on the customer side through a number of means. These include providing price incentives to customers to shift loading from high to

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low demand times as well as directly controlling customer assets such as hot water heaters, air conditioners, and others. This can also include voltage reductions (within regulatory limits) to reduce power levels at peak times.

7.5.4 Dynamic Rating Systems Thermal, electrical, and mechanical constraints limit the permissible power flows across OHLs. Historically, operators employed a static rating based on unfavorable weather conditions to ensure that conductor temperatures remained within design specifications. Dynamic monitoring can be established in real time to follow meteorological parameters, such as wind speed, ambient temperature, and solar radiation and fully utilize the potential of existing OHLs. In a fashion similar to OHLs, monitoring in real time, underground links can ensure greater flexibility for grid operation. The classical way of evaluating the capacity of underground cable systems assumes a continuous load at full capacity and establishes the resulting impact on cable temperature. However, a main difference between overhead and underground circuits is thermal inertia. It could take up to several weeks for a cable to reach its steady-state temperature after applying a load step, depending on moisture levels and soil characteristics, whereas an OHL requires no more than half an hour. From a TSO perspective, operating at maximum capacity for long periods rarely occurs. In particular, operators need to respect the appropriate reliability and reserve capacity criteria. The result of these provisions is that many power circuits may never reach heavy-loading situations. The steady-state loading hypothesis for cable ratings usually includes conservative assumptions about impactful parameters’ values, such as ambient temperature and soil thermal resistivity. These considerations may lead to oversized conductors and unnecessary extra costs. To optimize the modeling required to operate a cable closer to its physical rating, real-time knowledge of the cable’s surroundings and loading is required. A common way to obtain this information is by using distributed temperature sensor (DTS) measurements. By using an optical fiber, a DTS can detect cable hot-spots by measuring the cable temperature along tens of kilometers, with accuracy near 1
C and a spatial resolution close to 1 m. For the past 20 years, optical-fiber sensors were systematically installed in dedicated ducts placed in parallel to all new underground power lines. Intended for communication and protection purposes, the optical fibers can also be used for thermal monitoring. Flexible ac transmission systems (FACTS), can be used to provide control of ac transmission system parameters to increase power-transfer capabilities, and to provide connections between asynchronous networks; but, until now, most FACTS devices were installed mainly to address stability and voltage issues. To

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date, the deployment of FACTS devices has been limited due to the equipment’s high cost and large footprint and the lower anticipated need for resolving voltage and stability issues. Devices, called Smart- Modules (in this case, using FACTS technology developed by Smart Wires), can be used to adjust the transmission system transfer capacity by increasing a link’s impedance, thus redirecting flows toward less constrained lines. These solutions are available for grid planners to resolve overloads and rapidly adapt the network by redirecting the power flow instead of building new lines. Similar in purpose to the DLR solutions, Smart Modules are a way to develop flexibility in grid operation by influencing the flows on the lines.

8

Considerations in the Light of Emerging Governmental Climate Initiatives and Technological Change in the Context of Conventional Grid Solutions

In this chapter issues relating to the coordination of asset investments for system development with investments for sustaining the existing assets have been discussed. Both areas of asset investment are subject to risks. On the asset sustainment side, risks relate to investment timing; investing too late risks in-service failure and significant consequential impacts to corporate KPIs, while investing too early incurs additional and unnecessary costs and wastes useful asset life. On the system development side, utilities need to develop reliable system load projections, deal with unpredictable DER developments, new impactive technologies that can either significantly increase or decrease demand, as well as impactive government initiatives such as net zero 2050 that could have massive impact on system demand. System development planners are facing the challenge of system development asset investment planning in an environment that appears to be almost totally unpredictable for the next decade and maybe more. Will net zero 2050 initiatives that are projected in many countries happen? Or not? Or how by much? Or when? Or where? Or what? etc. How can system development planners manage asset investment risk in such an unpredictable environment? Asset sustainment investment managers worry about uncertainty in asset condition assessments and the probability of asset failures and getting the data right for rigorous business case analysis; but by comparison with the uncertainties in system development planning, the degree of uncertainty in asset sustainment investment decisions might be considered to be relatively minimal. Given the business, governmental, technological, and economic uncertainties in the prospective decades, what strategy can system development manages adopt? One approach is to better understand unpredictable risks. The dimensions of unpredictable risk are illustrated below.

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The dimensions of unpredictable risk

The figure includes the two conventional axes of risk, namely, the probability of events happening and the extent of impact of such events. As illustrated, the unpredictability may exist on both axes. Research on this topic has defined three types of risks (Hopkin 2010), first, risks that are taken in a passive or defensive strategy, secondly risks from events that are expected to occur but the impacts of which are unpredictable, and thirdly, risks that are taken opportunistically in proactive strategy. In the context of system development planning, examples of these forms of risk include: 1. Passive or defensive: Lack of investment in replacement or new assets, or at the wrong place or at the wrong time, leaving the system unprepared for new requirements 2. Expected events: Weather events such as major hurricanes in some geographical regions are known to occur on a regular basis; however some utilities do not invest in assets to build resilient systems to withstand extreme events (Texas Tribune). In the context of Net zero 2050, utilities may know that demand will grow significantly, yet they underestimate the extent of the growth in demand and suffer brown outs, poor service, and higher costs to accelerate the in-service of needed new assets. 3. Proactive: investments made in new assets or capacity upgrades on the assumption of increasing load and system demand may not occur; but which turns out to be unnecessary because distributed generation developers invest in assets that reduce system capacity needs. A first and obvious step in managing unpredictable risks is to follow ISO31000 Risk Management – Principles and Guidelines on Implementation and ISO 31010 Risk Management – Risk assessment Techniques to put in place organizational

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elements and competencies for risk management methods and processes and to assess known and reasonably foreseeable risks. However, in the context of system development planning, many of the types of events in the next several decades are actually unpredictable. For example, the – where, what, when kinds of issues with the development or otherwise of DG, and the timing, incentives, public, and business response to government net zero 2050 initiatives. The approach taken in the National Grid study of the future power system referred to earlier [National Grid ESO] uses a scenario approach intended to span the range of likely outcomes. Similarly a recent CIGRE technical brochure [CIGRE WG C6.27] also describes the use of scenario analysis as a means for assessing unpredictable outcomes. As discussed earlier in this chapter and in Case Study 21 in Part 2, initiatives such as by PJM to look at transmission congestion issues and reliability issues and plan for reinforcement of their system are examples of building resiliency into a network. Utilities regulators and governments have options as to decide if and how much resiliency they want to invest in (at rate payer expense) into their power systems networks. Three options and their costs/benefits are illustrated below.

Alternative strategies in an unpredictable world (Gibson and Tarrant 2010)

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The first option is to invest minimally and carry on with the status quo. This evidently describes the situation in ERCOT, which led to numerous and protracted power outages and significant impact damage during a 2021 Texas cold weather event [Texas Tribune]. The second approach is to adopt a preparedness stance, which recognizes possible adverse events and where steps are taken to be prepared for such events. A good example of this is the practice of many North American utilities to stock spare distribution system equipment (poles, pole-top transformers hardware, etc.) and to have standing agreements with neighboring utilities to provide emergency assistance in the form of repair crews and equipment, should events require them. The third approach is to invest in additional assets and systems to build in system redundancy and capacity necessary to cope with unexpected events. This approach tends to minimize the negative impacts of unexpected events, but it also increases the financial risks associated with bad guesses and mistakes in investing in assets that turn out to have been not needed or are stranded. In the end, the issue of how much resiliency utilities should invest in and regulators approve is a matter for governments to decide. New and emerging technologies can contribute both positively and negatively in the power systems of the future. With governmental pressure to move economies increasingly to be low or net zero carbon, storage, hydrogen-based, and renewable technologies become more important and pervasive. As discussed in Chap. ▶ 7, demands on electric power systems are expected to grow significantly with the increased generation being largely made up by wind and solar resources. Increased storage capability on power systems can play a very important role not only when wind or solar production is not available, but also under transient conditions to provide stabilizing services. Because wind and solar generation resources are predominantly connected asynchronously through inverter-based technologies, they have limited ride-through capability under system disturbance conditions. Some countries have advanced more quickly that others in the trend toward low carbon power systems and have obtained experience with the problems that can ensue. Australia, for example, has suffered blackouts as documented in recent articles [Mancarella and Billimoria] as have counties in the European Union and the USA. The table below illustrates a view of the problems and potential solutions to some of these issues.

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A summary of the problems and mitigation approaches facing low carbon electric power systems [Mancarella and Billimoria] ROCOF ¼ rate of change of frequency, PFE ¼ primary frequency response, DER ¼ distributed energy resource

In systems with significant asynchronously connected generation, maintaining traditional capacity margins may well be insufficient depending on the types of available capacity or spinning reserve. The ability of conventional thermal generation sources to ramp up fast enough to avoid under-frequency protection actions is limited. Hydraulic generation and storage sources have greater ramping capability and system operators and/or regulators will need to take action to prevent system states vulnerable to such contingencies.

9

Summary and Conclusions

Some things are known with certainty while others with less certainty and some with no certainty at all. Clearly asset managers know with certainty that system development investments need to be coordinated with asset sustainment investments. There

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are risks and uncertainties in investment decisions for asset sustainment, as there are, for system development investments. The risks in asset sustainment investment decisions relate to knowledge of asset condition, probability of in-service failures, and the extent to which the timing of investments can be optimized. The risks in system development investment decisions relate to the uncertainty in system demand and the unpredictable actions of independent market players, DER developers, governments, regulators, and customers. The rate of change in technologies, environmental, governmental, and regulatory initiatives requires an adaptive and proactive planning response. Utilities that are vertically integrated have the opportunity to facilitate close cooperation and coordination of system development planning versus asset sustainment planning at both the transmission and distribution level in the full knowledge of the generation supply mix and plans going forward. Few such utilities exist. As a consequence reregulated TOs and DOs need to interact with numerous commercial entities that may be transparent on near-term projects; but likely not willing to discuss any developments in the medium-to longer-terms. Regional transmission system operators need to set up processes to facilitate cooperation. For example, the US based RTO, PJM, has developed regional and subregional transmission expansion planning processes and committees involving all of their RTO member TOs. [PJM Planning] One of the difficulties in these processes is the planning horizon dichotomy between asset sustainment decision-making and system development planning. Definition of end-of-life of assets is a complex and relatively near-term activity. As a result, the planning horizon for asset sustainment investments is typically 5 years; but in some cases as much as 10–15 years depending on regulatory requirements. On the other hand, system development planning includes a very long-term planning horizon of several decades. The relative urgency in making asset sustainment investment decisions because assets have been deemed to be at end-of life may preempt to some extent system development planning decisions. The next few decades portend interesting times for asset managers and system development planners. Utilities will be faced with significant challenges going forward in what looks like an unpredictable future. Overall, with many governments coalescing on various forms of the net zero 2050 target, and the need for electric power systems to be increasingly resilient, the risks of underinvesting or excessively delaying investment appear to be greater than the risks of more aggressive investment strategies.

References ACCC, Australian Consumer and Competition Commission. https://www.accc.gov.au/regulatedinfrastructure/energy/retail-electricity-pricing-inquiry-2017-2018/final-report CIGRE WG37-27 Technical Brochure 176 “Ageing of the System Impact on Planning” 2000 CIGRE WG C6.27, Asset Management for distribution Networks With High Penetration of Distributed Energy Resources, TB 726 2018

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Gibson, C.A., Tarrant, M.: A conceptual Models’ approach to organisation resilience. Aust. J. Emerg. Manag. 25(2), 6–12 (2010). https://ajem.infoservices.com.au/downloads/AJEM-2502-03 Available free under Attribution-NonCommercial 4.0 International (CC BY-NC 4.0) https://creativecommons.org/licenses/by-nc/4.0/ Government of Australia. https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/ Environment_and_Communications/Electricity_and_AER/Interim_Report Hopkin, P.: Fundamentals of Risk Management: Understanding, Evaluating and Implementing Effective Risk Management. Kogan Page Publishers (2010) https://www.accc.gov.au/regulated-infrastructure/energy/retail-electricity-pricing-inquiry-20172018/final-report https://www.pjm.com/-/media/planning/rtep-dev/market-efficiency/2020-me-study-process-andrtep-window-project-evaluation-training.ashx Hydro One, EB-2011-0043 – 2020 Regional Planning Status Report of Hydro One Networks Inc. November 2, 2020. https://www.hydroone.com/abouthydroone/CorporateInformation/ regionalplans/Documents/HONI_OEB_RP_STATUS_REPORT_20201102.pdf Mancarella, P., Billimoria, F.: The Fragile Grid – The Physics and Economics of Security Services an Low-Carbon Power Systems, IEEE Power and Energy Magazine March/April 2021 National Grid ESO, Future Energy Scenarios 2020. https://www.nationalgrideso.com/futureenergy/future-energy-scenarios/fes-2020-documents PJM, Manual 14B: PJM Region Transmission Planning Process Revision: 48 Effective Date: October 1, 2020 Prepared by Transmission Planning Department. https://www.pjm.com/~/ media/documents/manuals/m14b.ashx PJM Planning. https://www.pjm.com/committees-and-groups/committees/srrtep-w PJM Regional Transmission Expansion Planning: Planning the Future of the Grid, Today. https:// www.pjm.com/-/media/library/reports-notices/2019-rtep/regional-transmission-expansion-plan ning-planning-the-future-of-grid-today.ashx?la¼en Texas Tribune, Texas leaders failed to heed warnings that left the state’s power grid vulnerable to winter extremes, experts say February 19, 2021. https://www.texastribune.org/2021/02/17/ texas-power-grid-failures/

4

Management of Aged Infrastructure Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Ge´rald Sanchis

Contents 1 End-of-Life Characteristics, Processes, and Failure Modes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 Power Transformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 Circuit Breakers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Overhead Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4 Protection and Control Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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G. L. Ford (*) PowerNex Associates Inc., Toronto, ON, Canada e-mail: [email protected] G. Ancell Ancell Consulting Ltd., Wellington, New Zealand e-mail: [email protected] E. S. Hill Loma Consulting, Milwaukee, WI, USA e-mail: [email protected] J. Levine Hydro One (Canada), Toronto, ON, Canada e-mail: [email protected] C. Reali Independent Electricity System Operator, Toronto, ON, Canada e-mail: [email protected] E. Rijks TenneT, Arnhem, The Netherlands e-mail: [email protected] G. Sanchis RTE, Paris, France e-mail: [email protected] © Springer Nature Switzerland AG 2022 G. Ancell et al. (eds.), Power System Assets, CIGRE Green Books, https://doi.org/10.1007/978-3-030-85514-7_4

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1.5 Power Cables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.6 Case Study: Consequence of a Medium Voltage Cable Failure . . . . . . . . . . . . . . . . . . . . . . . 2 System Impacts of Infrastructure Aging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 System Reliability and Power Quality Deterioration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 KPI Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3 Asset Risk Assessments, Trends, Regulatory Scrutiny, Shareholder Scrutiny . . . . . . . . 2.4 Falling Reliability Due to Underinvestment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 Case Study: Adequacy and Security Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Abstract

Asset management of aged asset infrastructure is of key concern to the electricity industry. The electricity industry has many long life and high-cost assets. There are many reasons for replacing or removing existing assets. The factors include unacceptable risk of asset failure, assets becoming redundant, asset capacity being insufficient to meet demand, assets unable to meet changed requirements for performance, and strategic decisions to move to new technologies. End-of-life characteristics, processes, and failure modes for electricity industry assets are examined. The consequences of infrastructure aging are outlined. The consequences include system reliability and power quality deterioration, reduction in ability to meet company and regulatory performance targets, and regulatory and shareholder scrutiny.

This chapter is concerned with managing aged infrastructure and asset end-of-life. Asset management of aged asset infrastructure is of key concern to the electricity industry. The electricity industry has many long life and high-cost assets. Expected service lives of four or five decades are typical for transmission lines and power transformers. The cost of installing new power transformers is significant. The cost of building new transmission lines or underground cables is also very high. There are many reasons for replacing or removing existing assets. The factors include unacceptable risk of asset failure, assets becoming redundant, asset capacity being insufficient to meet demand, assets unable to meet changed requirements for performance, and strategic decisions to move to new technologies. The probability of asset failure typically increases as assets age although this is not always the case. There is a point where the risk of in-service failure becomes unacceptable requiring asset replacement or removal. Assets are designed to be able to survive defined levels of electrical stresses such as transient high voltages and environmental stresses such extreme winds and ice/snow loading. Aged assets have a lower ability to survive stresses and become more likely to fail when the electrical and environment stresses are present. Assets can be made redundant by changes in the power system. New transmission lines of a higher voltage, which are operated in parallel with existing lines, may require the existing lines to be reconfigured to avoid overloading during outages of the higher voltage circuits. Connected parties may relinquish their connection

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making the connection assets redundant. The installation of new dead tank switchgear with integrated current transformers (CTs) make redundant conventional air insulated CTs. There is little value in replacing an aged asset if it is known the asset will shortly become redundant. Increases in electricity demand and power flows may eventually exceed the capacity of existing assets. These existing assets may need to be replaced with assets of higher capacity or have remedial action schemes (such as automated load shedding) installed to avoid asset overloading. The performance requirements for assets can change over time; meaning some assets that did and still continue to meet their original performance requirements may now fail to meet changed performance requirements. As an example, the existing protection relays at a substation may lack the ability to be integrated into an intelligent substation. A decision is made to replace the existing relays with new relays capable of being integrated into the intelligent substation so as to gain the full benefits of an intelligent substation. The power system was established or greatly expanded in many countries during the 1950s, 1960s, and 1970s. Much of this infrastructure is now aged and will soon require refurbishment and replacement. CIGRE Working group (WG) 37.27 (TB 176 2000) published a technical brochure titled “Aging of the system. Impact on planning.” The working group pointed out that the population demographics of most asset classes had a shape characteristic of an approaching “bow wave” (TB 176 2000, pp.17–18). The Figure below shows a chart from TB 176 showing the population age demographics (in the year 1998) of substation equipment based on data collected by the working group.

Age distribution for substations (Working group 37.27 2000, p.12)

Working Group 37.27 noted the uncertainty in establishing the actual life of each piece of equipment, the financial burden caused by the replacement expenditure profile, and the volume of asset replacement or life extension work affecting resources and skills planning.

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Assets have a finite service life over which the performance of the assets is expected to meet a defined performance standard. The performance of assets typically degrades over time due to usage, environmental exposure, and chemical processes in the materials making up the asset. The assets’ degrading performance is managed through maintenance activities until such point that it is economic to replace the asset. The following illustration shows how the end-of-life is determined by the weakening of asset capability to meet stresses.

A conceptual illustration of how end-of-life is a function of progressive aging and weakening of equipment (Updated from Working group C1.1 2006, Fig. 6.1)

The asset generally operates within a stress curve (blue probability density function on the left). The peak and left end of the probability density function shows the typical day-to-day range of stresses experienced by the asset. The asset will experience greater stresses (the right-hand tail of the probability density function) but these stresses will be much rarer. The “S”-shaped curves show the strength (cumulative withstand probability) for the asset at different stages of its life. As the asset’s strength reduces through aging processes, the stress and strength curves begin to overlap. The increasing overlap reflects an increasing probability that stresses will exceed strength and that failure may occur.

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There are options to delay progressive weakening of asset strength or to restore asset strength. The illustration below shows how an asset’s reliability changes at different stages of its life and the management actions to mitigate the reliability changes.

Stages of asset aging and possible management actions (Working group C1.1 2006, Fig. 6.5)

The asset is considered to be in a reliable state initially. Reliability decreases as the asset weakens with aging until a point where reliability has fallen to a level where the asset is deemed to have reached a degenerated state. As the asset ages further, there is a point where the asset is deemed to have reached an unpredictable state. In the reliable state, routine maintenance and repairs are used to delay the progressive weakening of the asset until it reaches the degenerated state. At this stage, asset refurbishment can be used to increase reliability and bring the asset back to the reliable state. Half-life refurbishment of major assets such as power transformers is a common management action. Once an asset has reached the unpredictable state, increased asset condition monitoring and eventually asset replacement are mitigations to manage risk. Asset aging depends on the original equipment quality, the quality of maintenance programs, and the operational stresses and environment.

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Asset aging influences (Updated from Working group C1.1 2006, Fig. 6.2)

The integrity of the equipment and systems originally put into service provides the base from which aging begins. The quality of design, design reviews, specification, manufacture, and commissioning can minimize risks of infant mortality problems and strongly influence how well equipment and systems perform in the long run. Competitive procurement processes used by utilities and the corresponding pricing pressures tend to force manufacturers to reduce design margins, use cheaper materials, and reduce costs, the long-term implications of which are uncertain, but not likely technically favorable. Provision of regular inspections and diagnostic tests or monitoring followed up with timely attention to correction of any apparent problems can have a very significant benefit in sustaining reliable operation and extending the useful life of equipment. Maintenance programs need rigorous documentation of diagnostic data, analysis to determine root causes for problems, post-mortem forensic analysis of failures and analysis to identify any trends in equipment performance. The operational duties and stresses imposed on the equipment relative to the design basis for the equipment critically affect the rate of aging. Typically, the harder some assets (e.g. overhead conductors, cables, switchgear, transformers) are worked, the faster they will age. Asset aging is not just the chronological age of asset but is related to the condition of the asset and its ability to meet the performance expected of the asset. The performance expected of assets generally changes over time. Assets built to standards and specifications in the past might no longer meet today’s standards for new assets. Materials used in the manufacture of assets in the past such as PCBs and asbestos are no longer used in assets and in some cases must be proactively removed and safely disposed of. Expectations of the service provided by assets are changing. Many modern assets are increasingly expected to have new capabilities such as asset

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monitoring and the ability to connect to local area communications networks. Distribution transformers are required to have higher efficiencies. Assets age and ultimately fail in differing ways. Power equipment designers and maintainers typically have deep knowledge of these processes and are a valuable resource to asset managers; nevertheless asset managers benefit from at least a basic understanding of such processes. The next few sections provide a basic description of such processes for several of the key types of assets. The next section describes the end-of-life characteristics, processes, and failure modes for different types of asset. That is followed by a section discussing the system impacts of aging infrastructure. Options for sustaining assets at end-of-life are discussed in the section after that, and the last section in this chapter introduces the differing asset management roles and functions as a transition to the next three chapters.

1

End-of-Life Characteristics, Processes, and Failure Modes

A determination of the end-of-life for an asset is possible if an assessment of its condition deems the asset no longer able to meet the performance required for that asset and that the risks of continued operation are unacceptable. End-of-life can occur through asset deterioration, obsolescence, changed asset performance requirements and asset failure. Assets deteriorate with time and usage, which reduces the performance of the asset. Assets may become obsolete as manufacturers cease making and supporting the assets. The performance required of assets can change over time and existing assets may not meet new performance requirements. Assets can fail through many different modes and some types of failures may render the asset unusable. Deterioration is the process by which an asset degrades until it is no longer to meet the performance required for that asset. The nature and extent of deterioration is different for different asset types. The extent of deterioration can depend on the type of maintenance and asset location. The performance of assets decreases with time through environmental and usage factors. Environmental factors such as salt pollution on assets in the vicinity of the sea can cause accelerated corrosion in the asset surfaces exposed to the salt. Usage factors such as high loading of transformers and excessive equipment operations for switches and breakers can reduce the service life of assets. Transformers operated at a higher temperature will in general have a shorter service life than transformers operated at a lower temperature. Circuit breakers are designed for a certain number of operations before maintenance or replacement. Transmission lines in a tropical environment are more likely to be affected by algae or plant growth. Wear on suspension accessories of transmission lines in a windy environment will progress faster. For many types of assets, the deterioration of one asset component does not necessarily signal end-of-life for the whole asset. Maintenance and replacement of the asset component at appropriate times can reduce failure risk for the particular component. The ongoing cost of maintenance for the asset component and the availability of replacement parts are factors in deciding whether to maintain or replace the asset.

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Each type of equipment (e.g., circuit breaker, power transformer) has a number of potential failure modes. Some of the failure modes can overlap and in some cases have synergetic effects. This section summarizes failure modes for several types of power system equipment.

1.1

Power Transformers

Power transformers approaching end-of-life can be expected to have more outages either due to minor faults or for repair. Some transformer components are repairable but some are not in which case the condition of these components deteriorate until a failure may occur. For example, insulation paper will typically become more brittle or degrade due to moisture and can irreversibly degrade until insulation breakdown occurs. Transformer bushings may also deteriorate until the bushing explodes. CIGRE working group A2.49 produced a technical brochure in 2019 on condition assessment of power transformers. The working group noted transformer degradation can arise from usage (e.g., loading, through-fault currents, high or low voltages) and environmental factors such as high ambient temperatures, corrosion, and seismic activity (Working group A2.49 2019). The continuing degradation of a transformer may eventually reach a point where the transformer will experience a severe in-service failure. The following illustrates a diagram from TB 761, which shows the relationship between diagnostic tools, failure modes, and condition assessment indices. Diagnostic indication

Failure Mode

Assessment Index

Periodic DGA Continuous DGA

Active part dielectric

Replacement

Electrical tests

Active part thermal

Failure/safety

Active part mechanical

Refurbishment

Bushing DGA

Tap-changer

Maintenance

Bushing PD

Bushing

Bushing replacement

Cooling degraded

Cooler refurbishment

Frequency response

Cooler efficiency Oil breakdown V

Oil

Oil treatment

Oil acidity Corrosion Tank Oil leaks

Power Transformer Failure Modes and Assessments

Tank refurbishment

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The acronyms DGA and PD stand for dissolved gas analysis and partial discharge respectively. The following chart summarizes some of the key transformer failure modes. Transformer failure modes (Tenbohlen et al. 2017) Failure mode Dielectric: Partial Discharge, tracking, flashover Electrical: Open circuits, short circuits, poor joints, poor contacts Thermal: General overheating, localized hotspots Physical chemistry: Moisture, particles, gasses, corrosion Mechanical: Bending, breaking, Displacement, loosening, vibration

Affected components Paper insulation, insulating oil, transformer bushings

Possible causes Insulation breakdown, contamination, core grounds

Bushing connections, terminals, tap changer contacts and connections Winding insulation, bushings, connections, tap changer Oil, insulating paper, copper conductors, tank

Improper assembly, maintenance, repairs, adjustment

Winding, leads, and connections

Inadequate site checks and commissioning, through faults, inadequate blocking or design

Inadequate specification, inadequate design, high ambient, defective cooling Inadequate monitoring and maintenance

CIGRE working group A2.37 conducted a transformer reliability survey. The results were published in a technical brochure (number 642) and a paper (Tenbohlen et al. 2017). Working Group A2.37 collected information about 964 major transformer failures between 1996 and 2010. The distribution of transformer failure modes is documented below. The most frequent failure mode for substation transformers in the survey was dielectric failure. The most frequent failure mode for generator step-up transformers was thermal failure. This may be explained by the higher average loading on generator step-up transformers. 60% Substation transformers

50%

Generator step-up units

Failure in %

40% 30% 20% 10% 0% Dielectric Electrical

Thermal

Physical Mechanical Unknown chemistry

Transformer failure modes (Tenbohlen et al. 2017, Fig. 4)

Dielectric mode failures involve insulation breakdown. Power transformer insulation deteriorates in service. Degradation of the liquid part (typically mineral oil) occurs through oxidation. Degradation of the solid part of the insulation system (the

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paper) is believed to start with oxidation then is dominated by hydrolysis and pyrolysis processes. The degradation of insulation results in chemical by-products detectable in oil, which can be used to assess the condition of the insulation and the likelihood of failure. Electrical mode failures may involve open circuits, short circuits, or poor contacts on the load tap changer, bushings, and windings. The causes of electrical mode failure include poor repair work, poor assembly, and externally caused damage. Thermal failure modes often develop as localized hotspots in winding exit leads and winding turn insulation. Thermal degradation results in the loss of physical strength of the insulation. This loss can weaken paper to the point where it can no longer withstand the mechanical duty imposed on it by short circuit forces, vibration, and mechanical movement inside of a transformer. Physical chemistry failure modes are a result of corrosion and contamination with particles, gas, or moisture eventually leading to dielectric flashovers in the insulation. Mechanical failure can result from external damage, seismic activity, and through faults. The effects of mechanical failure include winding displacement, winding damage, and insulation failure. The consequences of transformer failure can be extended outages, fire that damages other substation assets, danger to on-site staff, and oil leakage into waterways. Power transformers are filled with thousands of liters of insulating oil, which can be an environmental hazard if spilled. Tank failures can cause leakage of transformer oil, which can contaminate water catchments. Power transformers are typically installed within a bounded area that will retain oil spillage or oil leaks. The relative proportion of typical transformer failure consequences as reported in Tenbohlen is shown below. Most failures have no further consequence than removal of the failed transformer from service for repair or replacement. Others 4,88% Collateral Damages 1,24%

None 76,56%

Fire 7,16%

Explosion, Burst 5,91% Leakages 4,25%

Transformer failure consequences (Tenbohlen et al. 2017, Fig. 6)

Insulating oil leakages can pose staff safety and environmental issues. Leaked oil creates a slippery surface, may ignite, seep into the soil causing contamination or

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spill into nearby waterways. Insulating oil fires will also cause uncontrolled air pollution. There is a risk of a porcelain bushing failure causing an insulating oil fire or transformer explosion that could cause personnel safety hazards and adjacent equipment to be damaged.

1.2

Circuit Breakers

CIGRE working group A3.29 was set up to evaluate the deterioration of aging high voltage equipment and possible mitigation techniques. The working group published a technical brochure (number 725) in 2018. Chapter ▶ 3 of the technical brochure has a detailed description of the aging processes and mitigations for circuit breakers (Working group A3.29 2018, pp.63–121). Circuit Breakers approaching end of life will generally have an increasing likelihood of failure and need for maintenance. Circuit breaker degradation generally comes from the wear and tear associated with the number of operations and the size of the currents interrupted, over-voltages, seal material deterioration, and corrosion. The key rated service conditions which affect circuit breaker aging [TB725] are: • • • • •

Short circuit current (and duration) Normal continuous current level (impacts temperature rise levels) Dielectric stress Number of operations, and Mechanical load

The following summarizes circuit breaker degradation processes, affected components, and possible consequences. Example degradation processes for circuit breaker components Degradation process Electrical degradation

Mechanical degradation

Affected component 1. Increase of contact resistance 2. Electrical wear 3. Loss of dielectric strength 4. Reduced short circuit breaking capability 5. Change of Capacitance 1. Mechanical Wear 2. Fatigue 3. Relaxation 4. Loosening 5. Loose/sticking contacts

Possible consequences Overheating Contract and nozzle failure Weakened insulators Flashovers Circuit breaker does not clear faults, which results in the operation of backup protection Reduced short circuit breaking capability Abrasion, corrosion Mechanical cracking, reduced strength

Operational failure of circuit breaker (continued)

82 Material degradation

G. L. Ford et al. 1. Corrosion 2. Contamination 3. Chemical reaction with media decomposition by-products 4. Grease degradation/loss of lubrication 5. Increase of moisture

Decreased mechanical and electrical properties Reduced insulation properties Reduced insulation properties

Reduced mechanical properties

Working group A3.29 categorized circuit breaker failures [TB725] into two categories as shown in Failure types for circuit breakers Failure type Major. Failure which causes the cessation of one or more of its fundamental functions (for example, failure to open or close when required)

Minor. Failure of equipment which does not cause a major failure

Failure mode Does not operate on command Operates without command Electrical breakdown Locking in open or closed position Other major failure consequence (grouped for other categories) Air or hydraulic oil leakage in the operating mechanism Small SF6 leakage Oil leakage of grading capacitors Change in mechanical functional characteristics Change in electrical functional characteristics Change in functional characteristics of control or auxiliary systems Other minor failure consequence (grouped for other categories)

The consequences of major failures include outages or interruption when the circuit breaker fails to open during a fault, explosion, or fire damaging other substation assets and risk to on-site staff. If a major failure of a circuit breaker has occurred then the circuit breaker will be removed from service causing an outage of a power system equipment, e.g., a bus section, circuit, or transformer. The consequences of minor failures include air, hydraulic oil, or SF6 leakage, or reduced mechanical and electrical functional characteristics. Many recent circuit breakers use SF6 as the interrupting medium. SF6 is a synthetic gas that has excellent dielectric properties, is nonflammable and has minimal effect on the local environment in a sealed system. However, SF6 is a potent greenhouse gas with a global warming potential (GWP) of 22,800 (100 year time period). See (Glaubitz et al. 2014). SF6 circuit breakers can leak and care needs to be taken when installing or decommissioning SF6 circuit breakers to avoid leakage and any residual toxic decomposition products. Many countries have regulations concerning discharges of SF6 into the environment.

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The industry has undertaken extensive research into alternatives to the use of SF6 in response to concerns at its environmental impact. Working group B3.45 published a technical brochure (TB 802) in 2020 on the application of alternative gases or gas mixtures in MV switchgear. Bulk oil circuit breakers contain significant quantities of oil. Minimum oil circuit breakers contain a few hundred liters of oil. The circuit breaker oil is an environmental hazard. Older oil-filled circuit breakers can leak small amounts of oil due to aging seals and gaskets.

1.3

Overhead Lines

Overhead transmission lines have a number of key elements (conductors, insulators towers, poles, support hardware) each of which experience specific and differing wear and deterioration mechanisms as described in detail in CIGRE Green Book, Overhead Transmission Lines and summarized briefly herein. Examples of failure modes for overhead line components Component Steel Tower Wood Pole

Concrete pole Steel pole Cross-arms Insulators Conductor

Cause of failure Corrosion of structures and bolting Cracking of concrete tower footing Decay (rot) of wood poles at the base of pole where moisture can enter Decay (rot) of wood poles at the top of pole where moisture can enter Corrosion of the steel reinforcement

Corrosion at the base of the pole below ground level Decay of wood Mechanical stress due to being hit by objects or vibration. Cement growth cracking Corrosion, annealing, embrittlement

Consequence Tower collapse Tower collapse Pole break Weakening of cross arm attachment point and splitting Loss of structural strength Lumps of concrete falling off pole Pole break Conductor drop Increased corona noise Conductor drop Conductor break

The consequences of a failure of an overhead line can range from the forced outage of the circuit(s) that line is carrying to catastrophic failure where a whole group of towers or pole collapses following the collapse of one tower. Overhead line failures pose public safety and worker safety hazards. Overhead line spans that cross over roads may put the traveling public at risk if a conductor breaks and falls onto the road. Staff maintaining or repairing weakened towers or poles may be at risk.

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Protection and Control Devices

Protection and control devices have changed over time with technology developments. There are three main technologies: electromechanical, electronic, and microprocessor based. It is not uncommon to have devices of each of the technologies operational in the same substation. Electromechanical relays have long service lives (up to 70 years). Electronic/ digital relays have shorter service lives (typically 25–35 years). Microprocessorbased relays have service lives of 10–20 years or less. Older relays are often not supported by manufacturers beyond a few years, even if the company is still in business. Electromechanical relays and electronic/digital do not have the functionality or communications capabilities specified in modern protection schemes. CIGRE working group B5.08 published a technical brochure (number 448) titled “Refurbishment Strategies based on Life Cycle Cost and Technical Constraints.” The working group noted a number of factors that can cause a need for protection replacement or upgrade. These factors include extension of the primary configuration, equipment obsolescence, failure risk level, lack of knowledge about particular relays, maintenance costs, and need for increased performance and functionality. Modern protection systems generally have a self-diagnostic capability and can provide an alarm indicating failure. There are three general protection failure modes: • Protection fails (is incapable of detecting and tripping circuit breakers in response to a fault) and an alarm is provided to the operator. The operator may choose to take the protected asset out of service until the failed protection can be restored to service. • Protection fails and the operator is unaware. In this situation, the protection failure will be found following a fault on the protected asset. • Protection mal-operates opening a circuit breaker when not required. The consequences of protection failure vary. The consequence of protection failure can be removal of an asset from service (potentially causing a loss of supply or connection), the loss of supply and connection at multiple points following the operation of backup protection to clear the fault. The actual consequence of a protection failure needs to be determined individually for each protection system. Two main protection systems are often employed for important assets. Having two independent systems makes the failure of one protection system for an asset less critical.

1.5

Power Cables

CIGRE working group B1.09 looked at remaining life management of AC underground lines. The working group produced a technical brochure (number 358) in 2008. The working group classified the stresses on high voltage power cables into the following categories (Working group B1.09 2008):

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• Thermal: Due to the operating current under normal and emergency conditions. • Electrical: Due to operating voltage under normal and emergency conditions and due to impulse voltages following lightning and switching. • Environmental: Due to environmental conditions acting on the external sheaths of the cable (polymer degradation, metal corrosion). • Mechanical: Due to laying operations (bending), service conditions (load cycling or externally induced cyclic movements for submarine cables), or accidental dig in damage. The working group B1.09 summarized the most common defects for different types of cable as shown below.

Underground cable common defects (Working group B1.09 2008, Table 4.1)

Power cable failures range from minor to severe in nature. Minor failures can result in temporary outages. For example, the operation of an over-current protection system will result in an outage of the power cable. Severe failures can result in extensive damage to the cable necessitating repair or replacement. Repair or replacement of a damaged cable can result in extended outages. Severe failures can result in cable fires, which can pose a threat to public and staff safety.

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Case Study: Consequence of a Medium Voltage Cable Failure

A fire caused by the electrical failure of a cable joint in a medium voltage power at Penrose Substation in Auckland, New Zealand, caused a widespread loss of supply in parts of Auckland. The Electricity Authority of New Zealand commissioned an investigation into the fire (Electricity Authority 2015). The cable that failed was installed in 1996 and had the original joint replaced in 2001. The cable was one of 19 high voltage cable circuits and control cables in an in-air cable trench. The initial cause of the fire was electrical failure of the joint. A significant contributing factor to the spread of the fire was the number of cable lengths in the cable trench providing fuel and air in the cable trench providing oxygen for the fire.

Photograph of cable trench taken after the fire (from Electricity Authority 2015, Fig. 8 from appended Cable Consulting International report)

The power cables in the cable trench supplied over 39,000 electricity consumers. More than 75,000 consumers were affected due to the need to de-energize additional circuits to allow fire-fighters to control the fire. Electricity was progressively restored over the following 2 days. The Electricity Authority’s estimate of the economic cost to customers due to the loss of supply is between $47 million and $72 million.

2

System Impacts of Infrastructure Aging

Power system performance will worsen as the condition of the assets making up the power system worsens. The deterioration of assets will lead to increased numbers and durations of interruptions and outages across the power system. Worsened network performance will affect the ability of businesses to meet regulated performance targets and KPIs and may attract regulatory and shareholder scrutiny.

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Outages of aging assets for maintenance or replacement may result in further losses of supply, particularly in distribution networks where there is no redundancy. These losses of supply can provide an incentive for utilities to defer investment in lines in order to avoid breaching performance targets. Aging assets can also pose an increased risk to public and staff safety. Assets in areas the public can access may fail in ways that cause members of the public physical harm, e.g., electrocution or shrapnel. Aging assets in substations may be at risk of explosion or fire that can endanger staff on site.

2.1

System Reliability and Power Quality Deterioration

The risk associated with in-service failure increases as assets deteriorate. This also increasingly reduces the reliability of the power system. The effects of reduced reliability of the power system are increasing numbers and extent of interruptions and increased generation costs. Both forced and planned asset outages become more frequent and of longer duration as the condition of asset deteriorate further. CIGRE working group C1.27 produced a technical brochure (number 715) in 2018, which made recommendations on changes to the definition of reliability. The Technical Brochure states reliability, as understood in the utility industry worldwide, consists of two fundamental concepts: Adequacy and Security (Working group C1.27 2018). Adequacy is the ability of the electric system to supply the aggregate electric power and energy requirements of the customers at all times, taking into account scheduled and unscheduled outages of system facilities. Asset aging, which reduces asset capability (e.g., the forced de-rating of assets), can affect adequacy assessments. A power system having reduced adequacy increases the likelihood of load shedding and generation constraints. Asset aging, which results in an increase in power system faults, will likely increase interruptions to supply. Security is the ability of the electric system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system facilities. Asset aging, which results in reduced asset capability, will affect security assessments. Reduced asset capability can reduce the amount of load, which can be securely supplied and may require pre- or post-contingent load management or generation constraints to keep the power system secure. An example of a system adequacy and security check for the New Zealand power system is described in a case study later in this chapter. System reliability is often measured in terms of well-known industry standard metrics or by electricity not served (ENS) over a year. Typical measures include availability, frequency, and duration of interruptions. Reliability can be measured in many ways for example: • System-Minute: A system-minute is the energy transmitted through the system for a minute at peak load. The annual energy not served is divided by the system-

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minute figure. This measure is a relative measure, which permits comparison with larger or smaller systems. • Reliability: This is calculated as the percentage volume of electricity transmitted divided by the volume of electricity transmitted plus the volume of electricity not transmitted (due to interruptions). • SAIDI, System Average Interruption Duration Index: This index is calculated by dividing the sum of all customer interruption durations by the number of customers served. • SAIFI, System Average Interruption Frequency Index: This index is calculated by dividing the total number of customer interruptions by the number of customers served.

2.2

KPI Impacts

Most utility businesses have several Key Performance Indicators (KPIs), which relate to the company’s performance. Key Performance Indicators are quantifiable measures, which an organization uses to assess the effectiveness of its performance. Some KPIs will be linked to meeting regulated targets. Other KPIs can be based on staff and public safety impacts, reputation impacts, customer satisfaction levels, financial performance, and meeting contractual targets. Generation companies will have KPIs related to the capacity factor of generating plant. The capacity factor is the generation output (MWh) divided by the product of the maximum generation capacity (MW) and the number of hours in the period. Outages of generating plant or generator main output transformers will reduce capacity factors. Many organizations link KPI targets to performance bonuses. The organization’s staff are likely to receive lower bonuses if network performance or capacity factor is declining due to the aging of assets.

2.3

Asset Risk Assessments, Trends, Regulatory Scrutiny, Shareholder Scrutiny

Asset risk assessments are a way of managing system risk where there are aging assets. An asset risk assessment has two phases: risk identification and risk evaluation. The recently implemented common network asset indices methodology (CNAIM), initiated by OFGEM for distribution network operators in the UK, is an example. A case study from New Zealand is also provided in this chapter where an asset risk assessment was carried out. Risk can be evaluated quantitatively and qualitatively. CIGRE working group C1.38 [TB 719] investigated the valuation of risk in asset management and carried out a survey of international practice. Risk can be quantified for a number of areas: • Reliability (or loss of supply) and generation constraints • Environmental • Staff safety

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• Public safely, and • Direct cost of an event The valuation of risk is calculated as the probability of the risk event occurring multiplied by the consequence of the risk event (expressed in monetary terms). For example, if the probability of an event occurring in a year is 0.05 and the consequence of the event is the loss of supply of 10 MWh valued at $10,000 per MWh then the value of the risk is $500 per year. Where risk cannot be accurately expressed in monetary terms, qualification of risk can be done by determining the probability of failure on a scale (e.g., from 1 to 10) and the consequence of failure on another scale as discussed in Chap. ▶ 6. The result can be put in a matrix form such as by BCTC, (now BC Hydro) below.

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Qualitative risk ranking example (Working group C1.16 2010, Figs. 4.3-1 and 4.4.1)

Some regulators require transmission and distribution asset owners to disclose information about asset health and criticality. Examples include UK OFGEM’s DNO Common Network Asset Indices Methodology (see discussion in Chap. ▶ 2 of this Green book) and Australian Energy Regulator’s Asset Management Industry Practice Application Note (see discussion in Chap. ▶ 2 of this Green book).

2.4

Falling Reliability Due to Underinvestment

Aurora Energy is the sixth largest electricity distribution company in New Zealand. Aurora Energy is a wholly owned subsidiary of Dunedin City Holdings Limited, owned by the Dunedin City Council. A large portion of the Aurora Energy’s network was built during the 1950s to 1970s. Aurora Energy is now managing assets in their end-of-life phase. Under regulation in New Zealand, Aurora Energy is required to meet defined reliability targets. In 2016 and 2017, Aurora Energy reported breaches of its reliability targets. Aurora Energy was taken to court by the New Zealand Commerce Commission,1 which regulates distribution businesses. The Commission has alleged underinvestment in asset maintenance and renewal had led to the electricity distribution business breaching its regulated targets in 2016 and 2017 for interruptions and outages. Each breach carries a maximum penalty of $NZ 5 million. In 2018, the Commerce Commission (the electricity regulatory body) filed court proceedings against Aurora Energy, for breaching its regulated quality standards in 2016 and 2017 (Commerce Commission New Zealand 2018a). The Commission asked the High Court to impose financial penalties on Aurora. Aurora Energy disclosed to the Commerce Commission its breach of its quality standards in both 2016 and 2017. The Commerce Commission investigated the breaches and concluded they resulted from Aurora Energy failing to comply with good industry practice. Aurora Energy shareholders took decisive action in 2016 on becoming aware of the effects of historic underinvestment in its network (Commerce Commission New Zealand 2019). A new management team was established. The organization was refocused on investment and establishing Aurora Energy as a stand-alone organization. Capital expenditure has increased 250% in 2018 and 2019. Much of this expenditure is not recoverable under revenue caps imposed by the regulator. Historic and projected capital expenditure (Capex) for Aurora Energy are shown below. 1

The Commerce Commission of New Zealand is a government agency, which enforces legislation promoting competition in New Zealand markets. The Commerce Commission regulates some markets where there is little or no competition. The Commerce Commission is responsible for the regulation of distribution businesses in New Zealand.

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Historical Capex Trends 70

264.3%

300.0%

217.1%

60

250.0% 200.0%

$m

50 40

150.0% 66.4%

30

100.0%

(22.1%) 9.6% (9.0%) (38.3%) (20.1%) (16.2%)

50.0%

20

–

10 –

(50.0%) RY11

RY12

RY13

RY14

RY15

Commissioned assets (allowed) Capex % allowable Capex

RY16

RY17

RY18

(100.0%)

RY19

Commissioned assets (actual)

Aurora Energy capex expenditure (Commerce Commission New Zealand 2019)

Percentage SAIFI caused by defective equipment

The green columns show the allowed (regulated) level of expenditure and the blue columns show actual expenditure. Aurora Energy engaged WSP Opus in 2018 to undertake an independent review to determine the state of the electricity networks in Dunedin and Central Otago and to identify any critical assets at significant risk of failure. WSP found that overhead conductors, poles, and cross-arm assets were causing more than 50% of the network outages that were attributed to asset deterioration. The WSP Opus review found that the percentage of SAIFI caused by defective equipment had increased markedly between 2013 and 2017. 35%

y = 0.03x + 0.13 R2 = 0.95

30% 25% 20% 15% 10% 5% 0% 2013

2014

2015 Regulatory year

2016

2017

Trend of outages caused by defective equipment Percentage SAIFI caused by defective equipment in Aurora Energy’s network (Commerce Commission New Zealand 2018, Fig. 7.3)

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Case Study: Adequacy and Security Assessment

Transpower New Zealand uses adequacy and security margins to assess system reliability (Transpower 2019). Transpower New Zealand is the owner and operator of the New Zealand Power System. New Zealand has two AC power systems in the North and South Islands connected by an HVDC link (sometimes known as the Cook Strait cable). Most of the load is located in the North Island and much of the generation and hydro storage is located in the South Island. New Zealand has a large amount of hydro generation. Hydro storage is limited (months rather than years). There is a risk that extended periods of low rainfall into the storage catchments can result in hydro storage levels being depleted reducing the amount of available hydro generation. If the times of low hydro storage occur coincident with outages of other major plant (generation or transmission) then nationwide electricity conservation campaigns may be required. As part of managing security of supply, Transpower New Zealand calculates energy and capacity margins each year. The energy margins assess the likelihood of an adequate level of generation and, in the case of the South Island, the likelihood of sufficient HVDC south transmission capacity, to meet expected electricity demand during the winter. The capacity margin assesses the likelihood of adequate generation and HVDC north transmission capacity to meet peak North Island demand. The energy margin is the sum of available winter energy supply (GWh) divided by the expected winter energy demand (GWh) expressed as a percentage of total demand (GWh). The capacity margin is the sum of North Island generation capacity (MW) minus expected North Island peak demand (MW) plus surplus South Island generation available to be sent north via the HVDC link. The current security of supply standards specified in the New Zealand Electricity Governance Rules are 14–16% for New Zealand winter energy margin, 25.5–30% for the South Island winter energy margin, and 630–780 MW for the North Island winter capacity margin.

3

Summary

The performance of assets generally deteriorates over time and with usage until performance reaches a point where intervention is required to refurbish or replace the asset. The consequence of deteriorating asset performance is increased risk of failure of the asset. The asset may fail causing losses of supply, constraints on generation, and danger to the public and staff members. Failures may have severe consequences for the environment and reputation of the organization owning the assets. Each type of asset has a number of failure modes. Some of these will predominate depending on the environment, asset usage, and maintenance regimes. Expert assessment of asset condition can be used to estimate the probability of future asset failure; but using asset condition requires a condition monitoring regime for key assets. The consequence of asset failure can range from very minor to very major such as system wide blackouts. Asset Managers can use asset condition and the

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consequence of asset failure to prioritize maintenance, replacement, and refurbishment activities if appropriate monitoring practices are implemented. Shareholders and regulators have a considerable interest in trends in asset performance, particularly declining trends. The next three chapters in this Green Book cover the areas of Strategic Asset Development, Operational Asset Management, and Tactical Asset Management. The Strategic Asset Development chapter is concerned with the organizational and asset management frameworks over the lifetime of the assets. The Operational Asset Management chapter deals with implement asset management decisions in the short term (1 or 2 years) and the Tactical Asset Management makes asset investment decisions over the medium- to long-term planning periods of 5–15 years. Chapter ▶ 5 (Strategic Asset Development) describes the importance of senior management’s strategic leadership in the direction of the asset management program. Leadership responsibilities include developing an effective asset centric organizational structure with clear operational and tactical roles and responsibilities. The asset management framework needs to be aligned to the organizational context. The asset management framework for a vertically integrated business will be markedly different to the asset management framework for an Independent Power Producer or a transmission business as the nature of the assets utilized by each business and the business’ commercial drivers are quite different. Asset management leadership responsibilities include definition of the key performance indices, corporate risk appetite, and key financial analysis and decisionmaking parameters. The asset management risk framework will be closely aligned to the organizational risk management framework. Asset management policies, asset management strategies, and life cycle strategies for assets need to be developed. Chapter ▶ 6 (Operational Asset Management) is concerned with asset management decision-making from the operational to short-term planning time frames. Most of the medium- to longer-term asset investment decisions and plans have been already made by Tactical Asset Management and are implemented by Operational Asset Management. Operational Asset Management includes replacing assets, carrying out planned and unplanned asset maintenance, asset testing, and collection and analysis of asset condition information. Chapter ▶ 7 (Tactical Asset Management) considers the medium- to longer-term needs for asset investment coordination, planning, and justification. Asset investment decisions need to use both information from system development, which forecasts the future demand requirements (e.g., thermal capacity) for assets and information from operational asset managers about future asset performance (e.g., risk of failure) to determine the best medium- to long-term asset investment solutions. An important part of Tactical Asset Management is the assessment of risk across the system. The probability and consequences of asset risk need to be identified and quantified (monetized as far as possible). The consequences of in-service asset failure occur across a range of areas (interruptions to supply, environmental damage, safety risk to staff, and public and financial losses). Knowledge of the probabilities and consequences of asset failures allows investment expenditure

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prioritization and understanding of the implication of the consequences of asset investment decisions. The implications of a run to failure strategy can be compared to the implications of a maintain and repair strategy. The risk of critical assets failing can be reduced through online monitoring.

References Cable Consulting International Ltd.: Investigation into a Fire in a Cable Trench in Penrose Substation. Available at: https://www.ea.govt.nz/dmsdocument/20152-cable-consulting-international-ltdinvestigation-into-a-fire-in-a-cable-trench-in-penrose-substation. Accessed 22 June 2020 Commerce Commission New Zealand: Commission to file proceedings against Aurora Energy for breaching quality standards (2018a). Available at: https://comcom.govt.nz/news-and-media/ media-releases/2018/commission-to-file-proceedings-against-aurora-energy-for-breaching-qual ity-standards. Accessed 6 Feb 2020 Commerce Commission New Zealand: Aurora Energy independent review of the state of the network (2018b). Available at: https://comcom.govt.nz/regulated-industries/electricity-lines/projects/ aurora-energy-independent-review-of-the-state-of-the-network#projecttab. Accessed 6 Feb 2020 Commerce Commission New Zealand: Default price-quality paths for electricity distribution businesses from 1 April 2020 –Updated draft models: Companion Paper (2019). Available at: https://comcom.govt.nz/__data/assets/pdf_file/0030/180966/Aurora-Submission-on-compan ion-paper-to-updated-models-9-October-2019.pdf. Accessed 6 Feb 2020 Electricity Authority: Penrose substation fire inquiry report, 9 November 2015. Available at https:// www.ea.govt.nz/dmsdocument/20843-penrose-substation-fire-enquiry-report. Accessed 22 June 2020 Glaubitz, P., Stangherlin, S., Biasse, J.-M., Meyer, F., Dallet, M., Prüfert, M., Kurte, R., Saida, T., Uehara, K., Pascale, P., Ito, H., Kynast, E., Janssen, A., Smeets, R., Dufournet, D.: CIGRE Position Paper on the Application of SF6 in Transmission and Distribution Networks. CIGRE (2014) Tenbohlen, S., Vahidi, F., Jagers, J., Bastos, G., Desai, B., Diggin, B., Fuhr, J., Gebauer, J., Kruger, M., Lapworth, J., Manski, P., Mikulecky, A., Muller, P., Rajotte, C., Sakai, T., Shirasaka, Y.: Results of a standardised survey about the reliability of power transformers. In: The 20th International Symposium on High Voltage Engineering, Buenos Aires, Argentina, August 27 – September 01, 2017 (2017). Available at: https://e-cigre.org/publication/download_pdf/ISH2017_598-resultsof-a-standardized-survey-about-the-reliability-of-power-transformers. Accessed 6 Feb 2020 Transpower: Security of supply annual assessment 2019 (2019). Available at https://www. transpower.co.nz/sites/default/files/bulk-upload/documents/SoS%20Annual%20Assessment% 202019%20report.pdf. Accessed 6 Feb 2020 Working Group A2.49: Technical Brochure 761: Condition Assessment of Power Transformers. CIGRE (2019) Working Group A3.29: Technical Brochure 725: Ageing High Voltage Substation Equipment and Possible Mitigation Techniques. CIGRE (2018) Working Group B1.09: Technical Brochure 358: Remaining Life Management of Existing AC Underground Lines. CIGRE (2008) Working Group B3.45: Technical Brochure 802. Application of Non-SF6 Gases or Gas-Mixtures in Medium and High Voltage Gas-Insulated Switchgear. CIGRE (2020) Working Group B5.08: Technical Brochure 448: Refurbishment Strategies Based on Life Cycle Cost and Technical Constraints. CIGRE (2011)

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Working Group C1.1: Technical Brochure 309: Asset Management of Transmission Systems and Associated CIGRE Activities. CIGRE (2006) Working Group C1.16: Technical Brochure 422: Transmission Asset Risk Management. CIGRE (2010) Working Group C1.27: Technical Brochure 715: the Future of Reliability, Definition of Reliability in Light of New Developments in Various Devices and Services which Offer Customers and System Operators New Levels of Flexibility. CIGRE (2018) Working Group C1.38: Technical Brochure 791: Valuation as a Comprehensive Approach to Asset Management in View of Emerging Developments. CIGRE (2020)

5

Strategic Asset Management Gary L. Ford, Graeme Ancell, Earl S. Hill, Jody Levine, Christopher Reali, Eric Rijks, and Ge´rald Sanchis

Contents 1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 2 Roles, Functions and Responsibilities in Asset Management: Strategic, Tactical, Operational . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99 2.1 Asset Owner, Asset Manager, Service Provider Functions . . . . . . . . . . . . . . . . . . . . . . . . . . 100 2.2 Division of Responsibility by Roles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

G. L. Ford (*) PowerNex Associates Inc., Toronto, ON, Canada e-mail: [email protected] G. Ancell Ancell Consulting Ltd., Wellington, New Zealand e-mail: [email protected] E. S. Hill Loma Consulting, Milwaukee, WI, USA e-mail: [email protected] J. Levine Hydro One (Canada), Toronto, ON, Canada e-mail: [email protected] C. Reali Independent Electricity System Operator, Toronto, ON, Canada e-mail: [email protected] E. Rijks TenneT, Arnhem, The Netherlands e-mail: [email protected] G. Sanchis RTE, Paris, France e-mail: [email protected] © Springer Nature Switzerland AG 2022 G. Ancell et al. (eds.), Power System Assets, CIGRE Green Books, https://doi.org/10.1007/978-3-030-85514-7_5

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3 Responsibilities of the Asset Owner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Corporate Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Translating Business Objectives (from Asset Owner) into Performance Indicators (for Asset Manager and Service Providers) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 Development of Business Value Framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Stakeholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 Financial Stakeholders: Shareholders/Owners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 System Performance Stakeholders: Customers/End Users . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 Environmental . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4 Employees As Stakeholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5 Regulators As Stakeholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.6 Leadership: Organizational Roles and Responsibilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Risk Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1 Risk Appetite/Tolerance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2 Risk Acceptance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3 Risk Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4 Risk Analysis: Risk Matrices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5 Risk Reporting: Risk Registers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6 Asset Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.7 Examples of Power Delivery Risks and Risk Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Summary and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

103 103 104 104 106 108 111 114 117 119 120 124 127 128 129 130 130 133 135 136 138 139

Abstract

Asset Management practice divides duties and authority between three levels of utility management: strategic, tactical, and operational asset management. These may be separate entities or companies. Strategic Asset Management, as described in this chapter, outlines the requirements for the senior management of the firm. These managers are charged with ensuring the company meets its high-level goals, which include meeting financial requirements, minimizing impact to the environment, maintaining safety for the public and the work forces, and managing to an acceptable level of risk. This chapter outlines how the company identifies stakeholders and their goals, translates those goals into business values and objectives and eventually high-level key performance indicators, sets out the parameters of the risk management program, and establishes leadership with the company by defining roles and responsibilities for asset management and other utility personnel.

1

Introduction

As discussed in Chap. ▶ 1, many utilities in the 1990s, faced with stagnant load growth and pressure from regulators for more rigorous justification for investments in assets, made a transition to asset-centric organizations. In asset-centric organizational structures, the strategic leadership of senior management is a critical factor in implementing an effective asset management organization and function. Strategic issues such as definition of company values, key performance indices (KPI), and shareholder and regulatory risk attitudes need to be defined and communicated. Chap. ▶ 5 deals with these and other topics including, corporate financial constraints/incentives, monetization of KPIs or output measures, and corporate policies on asset insurance.

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This chapter provides the reader with guidance on the direction of the asset management program as determined by the leadership or top management of the company. The chapter addresses the following topics related to Strategic Asset Management: Roles and Responsibilities Organizational Roles and Responsibilities (Establishing for Asset Managers, Service Providers, etc.) Context of Organization Alignment Corporate Objectives Translating Objectives into Key Performance Indicators Business Value Framework

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Stakeholders and Their Expectations Leadership Asset Management Policy and Strategic Asset Management Plan Risk Management Business Impact Framework Risk Appetite Risk identification/Matrices Risk Acceptance and Insurance Examples

Roles, Functions and Responsibilities in Asset Management: Strategic, Tactical, Operational

Asset Management is a complete approach that involves the entire company from senior management to individual technicians. As described in Chap. ▶ 1, Asset Management functions are usually divided conceptually to clarify responsibilities and actions. TB 422 divides the functions carried out by asset managers in an assetcentric organizational structure into three categories. These categories are summarized in the figure below, which is based on information collected from earlier references such as TB422.

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Asset Owner, Asset Manager, Service Provider Functions

Strategic asset management is usually seen as a prerogative of the highest levels of management within an organization. One recent development in the power industry that coincides with the division of roles described above is the “decoupling” of the functions of the organization into three parts: • Asset Owner • Asset Manager • Service Provider Each of these “parts” of the organization is described in more detail below. Typically, most to all of the responsibilities for Strategic Asset Management rest with the Asset Owner. At many utilities, the three entities listed above are different companies; however, the model is still useful when all three are within the same company as the same functions are still present. In particular, the function of Asset Owner and Strategic Management fit together well. Tactical and Operational Management responsibilities are generally divided between the Asset Manager and Service provider, but the lines between the two are less distinct. TB422 and TB309 elaborate more on these functions: The Asset Owner is accountable for the business strategy, the direction of the network company, and the overall financing of the investments. The Asset Owner may be a government, the Board of Directors a corporation, or an investor that owns the network assets and is ultimately responsible for the network. The Asset Owner focuses on the overall business strategy, the business values, the business performance, and business risks. The Asset Manager (accountable for making investment decisions to balance asset/service performance, financial performance, and risk). An Asset Manager is engaged by the Asset Owner and assigned responsibilities for the management of the network assets. The asset manager focuses on improvement of return on assets over their full life cycle. The return considered is not only financial return, but return on all business values as set by the Asset Owner. The asset manager’s role is to balance the business risks (derived from business values), the business performance, and expenditures on assets. The Service Provider (accountable for making decisions related to delivering work on time, within budget, and in a safe manner in accordance with agreed specifications). The work on the network assets is undertaken by Service Providers who are engaged and controlled by the Asset Manager. Service Providers could be either internal or external to the business and could cover such areas as maintenance, engineering, operations, or corporate services. The service provider focuses on efficiency of work delivery: project execution within the limits of quality, time, and budget. Balzer and Schorn [Balzer, Schorn, 2015] provide additional information on how the roles interact, and the responsibilities of each in executing asset management. In

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particular, the Asset Owner directs strategy, controls finances, and interacts with the regulator. The Asset Manager is responsible for the technical operations and maintenance of the assets, and the Service Provider executes those tasks as directed by the Asset Manager. These roles were originally outlined by Bartlett on behalf of CIGRE WG C1.1 in 2002 [Bartlett, 2002]. The following graphic illustrates the division of responsibilities:

Responsibilities Associate with Levels of Asset Management

Asset Owner

Asset Manager “doing the right things”

Service Provider “doing the things right”

Overall business strategy Target settings (business values) Finance: tariff setting, billing Interface with Regulator, Customers Investment strategy and program Maintenance strategy Standardization Data Management Project management Technical consultancy Realization (maintenance, engineering) Data collection and handling

Responsibilities Associated with Levels of Asset Management [TB422, 2010]

TB 422 page 111 summarizes the different needs of the organization levels in the following way: • Strategic asset management is the development of information the asset manager needs to make asset management decisions conform to the organization’s risk attitude and key performance indicators. • Tactical asset management refers to quantitative analysis of optional asset management tactics to support and justify decision-making in the medium- to longerterms. • Operational asset management is the development of information needed by the asset manager to be able to effectively manage the work by the service provider in the near term. The Strategic Asset Management is also typically responsible for the longest term decisions for the company, while the Tactical Asset Manager and Operational Asset Manager are responsible for shorter term (usually 5–15 years for the Tactical Asset Manager, and 0–5 years for the Operational Asset Manager).

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2.2

Division of Responsibility by Roles

Technical Brochure 309 describes the functions of the Asset Owner as part of a survey conducted during the writing of the brochure. Twelve companies participated in the survey. The radial scale is the per cent agreement associated that the functions are properly associated with the respective asset management process participants. For example, 88% of survey respondents agree that definition of policy and direction is the function of the Asset Owner. Owner

Manager

External SP

Stores Management Network Switching R&D Investigations Fault Analysis &Failure Investigations Asset Database Management System Operation

Internal SP

Internal Asset Worker

Policy&Direction 100 Funding Regulatory Management 90 Budget Review/Approval 80 Business Development 70 60 50

Community Relations

40 30

Legal Compliance

Business IT

20 10

Financial support

0

Capital Expenditure Management Network Planning/Investments

Procurement

Customer Relations

Project Management

Maintenance Strategies Refurbishment/ Replacement Decisions

Engineering Design R&D Work Field Maintenance Test &Commission Project Erection

Risk Management R&D/New Technology Maintenance Management Expenditure targets

Asset management responsibilities by role [TB 309, 2006]

The detailed breakdown of activities indicates that 100% of the respondents conducted core AM activities in-house, that 90% of surveyed organizations have separated their Asset management function from the Service Provider function, while about 50% have separated the Asset Owner function from the Asset Manager function. The following graphic summarized that division of responsibilities.

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SLA

business plan

investment portfolio

Initiative Phase

feasibility

definition

Feasibility Phase

Approval Investment portfolio Owner

design

Design Phase

Approval Project development

Asset Manager accountable

engineering

build and construct

Construction Phase

maintain

Exploitation Phase

Site Acceptance Test

Approval Investment proposal

end of life

End of life

Service Provider accountable

Asset Manager executes

Service Provider executes

Process Profiles and Responsibilities [TB309, 2006]

The following [Ault et al., 2004] shows how organizations have separated the functions listed above: Type Separate business unit Separate legal entity Separate group in overall structure Part of corporate function Separate level of management

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Corporate Objectives

Respondent (%) 50 38 25 19 19

Asset Management begins with the fundamental premise that all asset management decisions should include consideration of the organization’s values. Asset Management applies this premise in decision processes at every level of the organization. The resulting alignment of decisions with criteria and value measures derived from the Asset Owner’s or senior management’s direction ensures that every asset management decision consistently supports the organization’s strategic objectives and delivers value to stakeholders [TB309, 2006]. Asset management is focused on

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optimizing the added value of its decisions and is therefore not simply a methodology designed to cut costs. Identifying values and developing corporate objectives to implement those values is typically the responsibility of the highest levels of the organization – in other words, the Asset Owner or Strategic Manager. The company directors or their surrogates are responsible for developing a “Vision” and “Mission” for the company. In most cases, these documents present goals that cover significantly more areas than are usually considered the purview of asset management as defined in this document. Company management will use the high-level objectives in the Vision and Mission statements to create objectives at the next level of the organization. These are typically Financial and Sustainability goals, which may more directly address how the company provides stakeholders value. To illustrate the corporate objectives, the annual reports from two utilities, Duke Energy (US) and TenneT (Netherlands) were reviewed and the results are presented in subsequent sections of this chapter. Note that many utilities do not publish their asset management plan objectives. However, those plan objectives must reflect the corporate objectives specified in publicly available documents. A key function of the Asset Owner is to “translate” the corporate objectives, such as those described here, into Asset Management objectives.

3.2

Translating Business Objectives (from Asset Owner) into Performance Indicators (for Asset Manager and Service Providers)

TB 422 outlines how the Asset Owner is typically involved with the Asset Manager in the process of turning company objectives into monetized key performance indicators (KPI). This process may seem straightforward, but rarely is in practice. For instance, the connection between strategic and operational KPIs is not easy to make. Therefore, the Business Value Framework is introduced. All KPIs relate to an area of performance of the company often referred to as Business Values.

3.3

Development of Business Value Framework

TB 422 also discusses that for the Asset Manager to make or propose the right decisions for the Asset Owner, the Manager must understand the requirements set

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out by the Asset Owners and stakeholders. To facilitate this, a Business Value Framework is derived from the Asset Owners requirements and agreed to by both the Asset Owner and Asset Manager. The assumption of this business value framework is that if the objectives and the values of the Asset Owner are clear, the risks concerning the assets with regard to the business values will also be clear. The performance of the electricity transmission company is measured by KPIs. The KPIs are related to the business values and therefore with the business risks. In many companies, the mission, vision, and KPIs have already been established before the Asset Management program was initiated. If not, a session should be held with the senior management of the company to establish the business value framework. Questions like “what is the company’s mission,” “what are the strategic objectives,” “what is agreed upon as to what is important for the company as a whole,” “what are the key performance indicators,” etc., need to be answered. From these questions the business values can be derived and defined. The KPIs are grouped in performance areas linked to the business values. See TB422 Figure 4.2-1 the example is derived from the corporate risk matrix of the Canadian utility, BC Hydro [TB 422, 2010]. Examples of Business values/ performance area’s

Description

Safety

The company values safety of employees and third parties.The business value “safety” contains performance elements like Lost Time Incidents etc.

Financial

The company values a sound financial position and system. The business value “Finance” contains financial performance elements

Quality of Service/ Reliability

The company values a good quality of service. The business value “quality of service” contains performance elements like Customer Minutes Lost etc.

Environment

The company values the environment. The BV contains performance elements like cost of environmental damage etc.

Example of Business Value Framework [TB422, 2010]

Note that the “Business Values” can be linked directly to the Asset Management objectives. (The Business Values above and the Asset Management Values in the previous section are from different Canadian utilities, and therefore do not match, but are similar). The development of the Business Impact Framework (the logical

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next step following the Business Value Framework) is discussed in this chapter in the section on Risk Management. Business values are typically “distilled” into a hierarchy to find measures closer to management action. The following is an example of such a hierarchy: • Business objective: Maximize system reliability (meet or exceed regulatory targets) • Key Performance Indicator: Monitor Unsupplied Energy at system level • Planning Index: Monitor Unsupplied Energy for utility regions, individual substations, etc.

3.4

Alignment

Defining the purpose of the organization is necessary, but not particularly useful if it remains only as a high-level objective in company public documents. The purpose and the goals of the Asset Management program must be implemented across the organization from top to bottom. An important area within the context of the organization is to have the Asset Management objectives formulated in a manner that makes them consistent with the utility’s overall corporate objectives. For example, AM objectives need to be aligned with organizational objectives to achieve the consistency of the objectives, decisions, and activities within the organization, to ensure that assets contribute value to the meeting of the organizational objectives. Asset Management enables an organization to realize value for itself and its stakeholders by alignment. This is done by translating its organizational objectives into Asset Management objectives. Both sets of objectives can then be fulfilled by asset-related decisions, plans, and activities, using a risk-based approach. By fulfilling these objectives, an organization realizes value. Example 1: Hydro Ottawa, Ontario Canada – Corporate Alignment The following example from Hydro Ottawa, diagrams its corporate alignment, and illustrates the flow of Asset Management objectives from the utility’s Corporate Strategic objectives. This diagram illustrates an example of alignment between corporate direction and Asset Management measurements via corporate objectives and Asset Management objectives.

Mission Vision

Asset Lifecycle Cost To reduce total cost of assets by managing the distribution system in a fiscally responsible manner through efficient planning, procurement, design and deployment of programs and projects over the asset’s lifecycle

Corporate Alignment – courtesy of Hydro Ottawa

System Accessibility To maximize system accessibility by reducing constraints for load and energy resource facility customers

Service Quality To deliver electric power in a form which meets our customer’s needs by increasing reliability and mitigating power quality issues which affect customer service Resource Optimization To maximize efficiencies of project schedules and costs by optimizing internal and external labour resources

Productivity Management To reduce operational and maintenance unit costs by increasing efficiency through investments

Environmental Stewardship To minimize our environmental footprint by reducing releases of controlled or environmentally damaging substances

Employee & Public Safety To eliminate or mitigate existing and potential risks to employee and public safety

Employee Competency To ensure employees are aware, competent, and empowered by requiring or providing appropriate education, training and experience

Value Optimization To maximize asset value by determining optimal asset replacements and optimizing capital and O&M solutions; comparing costs, benefits, and mitigated risks

Customer Engagement To empower our customers through consultations, utilizing their input in planning and construction processes

Health, Safety & Environment To minimize employee and public health and safety risks and environmental risks from distribution system activities

Resource Efficiency To maximize economic efficiency by minimizing costs associated with maintaining and operating the distribution system

Asset Value

External Compliance To maintain status as a distributor in good standing and preserve our distribution license by complying with all applicable regulations, laws, standards and acts

Internal Compliance To ensure internal and external requirements are met by adhering to internally approved policies, procedures, standards and controls

To maintain compliance with all internal and external requirements while managing the distribution system

Compliance

Corporate Citizenship We will contribute to the well-being of the community by cultivating a culture of innovation and continuous improvement

To maximize the realization of value from distribution system assets over their entire lifecycle through managing risks and opportunities

Organizational Effectiveness We will achieve performance excellence by acting at all times as a responsible and engaged corporate citizen

Corporate Strategic Direction

Levels of Service

Financial Strength We will create sustainable growth in our business and our earnings by improving productivity and pursuing business growth opportunities that leverage our strengths

To be a leading partner in a smart energy future.

To maintain and enhance leading performance of the distribution system through improving electrical service and alignment with customers’ expectations

Customer Value We will deliver value across the entire customer experience by providing reliable, responsive and innovative services at competitive rates

To create long-term value for our shareholder, benefitting our customers and the communities we serve.

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Stakeholders

To build the corporate objectives as described in the previous section, the Asset Owner must identify stakeholders and their expectations. For investor-owned and government-owned utilities, key stakeholder groups include the shareholders and the regulators. Typically, shareholders wish to maximize profits, or at least revenue, while minimizing “impacts,” which can include environmental, societal, and other impacts of company operations. Financial considerations are paramount for any Asset Owner, even for government-owned utilities. A government-owned utility may be more driven by a need to accomplish a societal mission (such as providing affordable, low-cost power, or supplying rural and other populations with low cost access to electricity) than by financial goals, but ensuring the cost remains reasonable is always an important goal. Financial performance can be measured in any of a number of ways, as described below. Most utilities are required by law to publish some or all of their financial statements for public scrutiny. All utility organizations, regardless of their ownership, have other corporate objectives beyond financial goals. In First-World countries these include environmental stewardship, employee growth, delivery performance, enhancement of the customer experience, and many others. In Third-World countries, these objectives may include, beyond those listed above, providing electricity to under-served and unserved populations, extending the hours of availability for electricity, economic development, and more. The following is a high-level graphic from the TenneT 2018 Integrated Annual Report that outlines some of the company’s Strategic Goals. TenneT has set seven strategic priorities to help achieve these goals [TenneT Integrated Annual Report 2018].

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Secure supply

Lead NWE integration

Innovate business

Engage stakeholders

Securing a reliable supply of electricity and facilitating the integration of sustainable energy sources

Leading the development of an integrated and sustainable NWE electricity market

Innovating and adapting our business for the future

Engaging with our stakeholders at all levels

Stakeholder Values – courtesy of TenneT [TenneT Integrated Annual Report 2018]

For transmission entities, the next set of stakeholders are the customers, who are interested in maximizing the performance of the delivery system, including ensuring a secure supply as shown above by TenneT, while minimizing their overall payments, including possibly the rates per energy or capacity used. This to an extent contradicts the financial goals of the shareholders. Ensuring that these goals are balanced is the overall responsibility of the Asset Owner, although implementing policies to ensure that this balance is achieved may be an asset manager responsibility. A number of other organizations or individuals are commonly considered stakeholders. The following graphic from Duke Energy [Duke Energy 2017 Sustainability Report – Stakeholders] shows many of these stakeholders.

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Academia Trade Associations

Communities

Risk Safety Management

Water Quality & Availability

Reliability & Resiliency

Suppliers

Affordable Energy

Innovative Products & Services Ethics & Compliance

Biodiversity & Habitat Protection

Media Employee Development & Engagement

Employees

Safety Is Our No. 1 Priority

Economic Development

Local, State & Federal Government

Customers

Air Emissions

Climate Change

Community Engagement

Diversity & Inclusion

Labor Unions

Cybersecurity

Customer Engagement

Environmental Advocates

Investors

KEY

Our Stakeholders What Matters Most

Stakeholder Values – courtesy of Duke Energy [Duke Energy 2017 Sustainability Report – Stakeholders]

TenneT, [TenneT Integrated Annual Report, 2018] identifies the following additional stakeholders beyond those listed by Duke Energy: • Debt investors and Rating Agencies • Other European TSOs • Nongovernment Organizations (NGOs) beyond environmental organizations TenneT, like many other organizations also publishes a Materiality Analysis that outlines how TenneT engages with its stakeholders to understand their needs. Many but not all of these objectives are part of asset management. In particular, how the company spends its money on assets and its overall performance are key asset management areas.

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A critical function of asset management is therefore to provide clarity in linking corporate objectives with business values and related key performance indicators (KPIs) that can be measured to monitor business performance. Examples might include reliability targets; operating, maintenance, and administration costs/customer; number of and severity of personnel injuries; the number of corrections in decisions and activities forced by the regulator; and so on [TB 309, 2006]. The following paragraphs discuss these concepts, then illustrate how two companies (Duke Energy and TenneT) manage the relationship between corporate objectives and key performance indicators on a strategic level. Here the Asset Owner establishes what to measure and how to define acceptable performance. These KPIs are still high level – but each can be “broken down” to more specific KPI for individual entities or parts of the organization.

4.1

Financial Stakeholders: Shareholders/Owners

Financial performance is considered key to asset management by the Asset Owner. Investor-owned utilities must provide profits, in the form of dividends to shareholders or face management replacement. Government or publicly owned utilities may not have profits as a goal per se, but must collect sufficient funds to invest in the system to achieve the goals of other stakeholders (as discussed below) and to have the necessary financial health to be able to borrow money when needed at reasonable rates. Standard financial reporting relates to the entire enterprise and is the responsibility of those above the asset management program. Many factors influence the sales of an electric utility – the rates allowed by the government, the weather during a reporting period, and overall economic activity. While the Asset Owner is responsible to the shareholders for financial returns, they must determine which activities can be controlled through asset management. Establishing the required profit or rate of return is usually beyond the scope of responsibility of individuals in Asset Management, who nevertheless are constrained to operate under budgets developed with those rate of return targets in mind. In an ideal world, Asset Management would determine the funds needed to balance optimal system performance with cost, but this is rarely the case. For an investor-owned utility, return per share is a common metric for performance. Duke Energy in 2018 provided an adjusted diluted earnings per share of USD 4.72. This was considered a good year for Duke Energy. Shares at Duke Energy have grown over the last few years at 4–6%, within the desired range set by the company. Investor-owned utilities also monitor the share price. For example, Duke Energy shares increased to USD 84.11 from 77.62 in 2018, an 8.3% increase. The associated graphic on the following page is a sample summary of financial statistics [Duke Energy Annual Report, 2018].

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d

Significant transactions reflected in the results above include: (i) regulatory and legislative charges related to Duke Energy Progress and Duke Energy Carolinas North Carolina rate case orders and impairment charges in 2018 (see Notes 4, 11 and 12 to the Consolidated Financial Statements, “ Regulatory Matters,” “Goodwill and Intangible Assets” and “Investments in Unconsolidated Affiliates”); (i) the sale of the International Disposal Group in 2016, including a loss on scale recorded within discontinued operations (see Note 2 to the Consilated Financial Statements, “Acquisitions and Dispositions”); and (ii) the acquisition of Piedment in 2016, including losses on interest rate swaps related to the acquisition financing (see Note 2).

b

Prior year data has been recast to reflect the classification of the International Disposal Group as discontinued operations and is reflect the impacts of new accounting standards.

Financial Information – Duke Energy [Duke Energy Annual Report, 2018]

As noted, asset management is an influencer on the financials, but not the only determining factor. For example, asset management contributes to performance by assuring security of supply and to financial health by ensuring equipment is available

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and able to serve load, provide capacity, etc. Monitoring equipment and system performance to ensure availability is described in the following section under System Performance. Good system performance may increase revenue, but also can demonstrate good financial health to facilitate access to capital markets for investment resources. Asset management also contributes to cost, as ensuring assets are reliable and available costs money. Most companies establish performance metrics for the costs associated with asset management – maintenance, operations, salvage, and engineering (as appropriate). The costs may be divided into CAPEX and OPEX, as described in more detail in Chaps. ▶ 6 and ▶ 7, by region, asset class, or in any number of ways. Costs may also be evaluated based on asset replacement value or other factors. The Asset Owner must determine how to best assess the costs associated with assets. For in-house Asset Managers, usually the Asset Owner/Top Management will establish budgets with an appropriate level of detail to provide direction. The budget can be based on past budgets or on a more detailed review that examines the mean life and standard deviation of life span for the entire asset population to determine which assets to replace and when to replace those assets. The Asset Owner may choose to run simulations to make this determination [Balzer, Schon, 2015]. Asset Owners typically provide at least a review, in the appropriate level of depth, of projects to enhance or expand the system as discussed in Chap. ▶ 3. Justifying investments for asset sustainment and their timing over regulatory time frames or longer planning periods is the main responsibility of the Asset Manager as discussed in detail in Chaps. ▶ 6 and ▶ 7. Financial considerations may be different for publicly owned utilities. For example, TenneT found that even though budgeting could be a constraint, other factors such as outage planning and manpower availability were more likely to constrain work. Utilities typically report results such as the following [TenneT Integrated Annual Report, 2018].

Financial Information – TenneT [TenneT Integrated Annual Report 2018]

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System Performance Stakeholders: Customers/End Users

The most important customer value is high system performance – reliable and secure supply of electricity. As noted in the TenneT Annual Report [TenneT Integrated Annual Report, 2018]:

Mission Statement – TenneT [TenneT Integrated Annual Report 2018]

TenneT operates onshore and offshore networks and monitors the grid availability for each. In addition, TenneT monitors interruptions and energy not transported for the onshore grid, as shown in the graphic from the annual report below. In the body of the report, TenneT explains significant events that impacted the grid availability as well [TenneT Integrated Annual Report, 2018].

Grid Performance – TenneT [TenneT Integrated Annual Report 2018]

Duke Energy also assesses security of supply. Their Sustainability Report for Operations [Duke Energy 2017 Sustainability Report – Stakeholders] cites the goals in power delivery that Duke Energy sets every year for outage number and duration. Note that these are distribution performance indicators, not transmission indicators. Some companies use a contribution to distribution performance by transmission outages as a metric as well. Duke Energy found that the weather was 40% worse during the first half of 2017 than previous years, resulting in a 10-min increase in average customer time without power. During the second half of 2017, the weather returned to normal (with the exception of a large hurricane) and the average time without power decreased by 3 min, resulting in a net increase of 7 min shown below. The number of outages remained stable. Duke Energy also routinely assesses generation reliability.

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Outage Statistics 2017 2014

2015

2015

2017

Target

Average number of outages1,2 (occurrences)

1.13

1.16

1.17

1.18

1.18

Average time without power1,2 (minutes)

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144

151

135

1 Outages with a duration greater than 5 minutes; statistics are reported per customer, excluding major storms. 2 Lower numbers indicate better performance.

Outage Statistics – Duke Energy [Duke Energy 2017 Sustainability Report – Stakeholders]

For both companies, these are high level indicators, and not necessarily useful in making asset management decisions. Although not shown here for TenneT, both companies have acceptance criteria for the KPI monitored. Each secure supply KPI can be broken down by region or area and trended over time to detect improvements or declines. In addition, the Asset Manager can compare the values with benchmark values from equivalent companies. Asset Owners can also require monitoring of other supply- and reliability-related parameters. These include MAIFI (momentary average interruption frequency index), ASAI, and several others. As an alternative to reliability measures or standards, the Office of Gas and Electric Management (Ofgem) in the UK has developed targets for the three transmission providers in the UK for power losses due to outages caused by asset failures. Ofgem has also set significant monetary values for energy not supplied for use in asset management decision-making [UK RIIO ET-1 Report, 2018].

Reliability Targets and Scores – Ofgem [UK RIIO ET-1 Report, 2018]

Ofgem also developed targets (Network Output Measures NOMS) for Energy Not Supplied (ENS) for the three TSOs (National Grid Electricity Transmission, Scottish Power, Scottish Hydro Electric), as follows [UK RIIO ET-1 Report, 2018].

Energy Not Supplied (ENS) Targets and Scores – Ofgem [UK RIIO ET-1 Report, 2018]

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In this same area, the Asset Owner can require Asset Managers to compile customer complaint numbers and power quality statistics and develop acceptance criteria for each. The following is an example [UK RIIO ET-1 Report, 2018].

Customer Satisfaction Targets and Scores – Ofgem [UK RIIO ET-1 Report, 2018]

In the UK, these are regulatory requirements, but could also easily be used by the Asset Owner to assess performance. The Asset Management organizations (if a separate legal entity) are paid according to their performance. For Asset Managers within the company, remuneration in the form of performance bonuses, etc., is also determined by the system supply and company’s performance against the NOMS and internal KPIs. Most companies have goals in the supply area that require action by Asset Managers. The Asset Owner may not set performance metrics in these areas, but may expect implementation of particular programs in them, at a reasonable price. One such area is in smart meters. As a distribution utility, Duke Energy has deployed a large number of meters that enable customers to obtain real-time information on usage. This enables customers to make better decisions on when to use electricity (assuming time-of-use rates), which clearly impacts revenues. This also impacts Asset Management in that the meters themselves require maintenance and incur operational costs. Duke Energy and TenneT have established other security of supply-related goals as well. Both utilities see cyber-security as a critical area for ensuring grid supply, and have started initiatives (which may be implemented by Asset Managers or Service Providers). The following lists some other supply related goals/initiatives that might impact Asset Management: • Installing more sensors to predict equipment condition (Duke at its power plants; these may go in service at power delivery in the future) • Reducing theft of electricity (Duke for gas, may go in service for electric delivery in the future with smart meters), which saves customers money in the long run • Managing the supply chain (taking action to mitigate the decreasing the number of suppliers and the lack of qualified in-house staff) (TenneT), which reduces utility costs • Reducing outage planning, due to the faster pace of renewables integration (TenneT) • Improving system balancing with new renewables, due to increased volatility of renewables in real-time weather conditions (TenneT). TenneT is also concerned about declining service metrics as its assets age. This is likely a problem for Duke Energy and many other utilities as well. Lastly, TenneT is concerned about the phase out of coal and nuclear plants in its German service area and how a reduced proportion of base-load conventional generation will impact system stability and power delivery.

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Although not specifically mentioned by either utility, some companies review asset utilization as part of Asset Management. Ideally, assets are utilized to the maximum extent permissible, given the need to provide sufficient system margin for asset failures or outages. Usually, this is an Asset Manager responsibility, although the Asset Owner will review plans and their justification as part of the financial reviews discussed in the previous section, to ensure capital money is well spent. This may also be an area for review by the regulator. Part of the costs associated with customer bills are those that involve costs of operating the transmission and distribution systems. Customers have a vested interest in both improving reliability and reducing operating costs. To this end, both goals are satisfied to an extent by reducing congestion costs – higher congestion implies the system is less reliable and the costs associated with congestion raise bills. Therefore, customers may benefit more from increased capital spending and reduced operational spending when the utility makes investments in capacity expansion. In every case, the Asset Owner and the Asset Manager will have to reach an agreement on the amount of detail of the KPIs and how the KPIs are used to make decisions at the strategic, tactical, and operational levels.

4.3

Environmental

The environment is a particular concern for the public and for regulatory compliance by utilities. Energy creation and delivery has always resulted in an impact to the environment. Both Duke Energy and TenneT have spent considerable sums to protect and enhance the environment from grid activities. The following outlines the goals of TenneT in the environmental area [TenneT Integrated Annual Integrated Report, 2018].

Environmental Performance – TenneT [TenneT Integrated Annual Report 2018]

The most pressing environmental issue is climate change. Power delivery contributes to climate change through three main means: carbon-based fuels

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used in vehicles and to heat buildings, leakage of SF6 gas, and electric losses on the system (which require more generation and therefore more CO2 if the generation is fossil based). To address climate change, TenneT has assigned Internal CO2 pricing to place a monetary value on its emissions. This adds a price to “high loss” projects and motivates the company to implement projects with smaller losses. This in turn becomes a metric for evaluating Asset Manager’s projects and other activities and may impact Asset Management Plans. For SF 6, TenneT is exploring better ways to prevent leakage and alternative gases for interruption purposes. Both of these initiatives will impact Asset Management Plans. TB541 provides a great deal of information on how utilities have implemented plans to manage and reduce greenhouse gases (GHG). Duke Energy has also established a metric for SF6 emissions, as show below. The initiatives to reduce copper use and oil leakage and spills will also have an impact on the projects and the maintenance of equipment that are part of Asset Management Plans. Oil spills caused by in-service failure of assets can be significant and the monetized costs for clean-up need to be included in risk-based decisionmaking associated with asset end-of-life management. Other utilities have also addressed waste generation (from transmission operations) as an environmental concern and created initiatives to address those concerns. As with the CO2 and SF6 emissions, the Asset Owner and the Asset Manager will determine an appropriate KPI – for instance, number of kilograms per year permitted – to monitor these objectives. One final requirement for the environment applies to several other areas as well, namely, energy efficiency and conservation. Most utilities have established initiatives for energy efficiency and conservation. This can mean reducing the losses on the transmission and distribution system (as described above). It can also mean initiatives to reduce consumer energy consumption and peak demand. These changes can also reduce utility revenue, although some regulators will provide incentives for programs of this type. In any case, reductions in energy usage can result in different choices for project and for maintenance tasks put in place by the Asset Manager.

SF6 Emissions – Duke Energy [Duke Energy 2017 Sustainability Report – Stakeholders]

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Employees As Stakeholders

Asset Owners generally have goals for employees as well. These can vary from appropriate pay to increasing or maintaining diversity. Most have little impact on equipment asset management as discussed in this book. One employee-related performance area that has an impact is safety. Most organizations track lost time due to accidents or similar metrics. TenneT has implemented the following [TenneT Integrated Annual Report 2018]: To measure the impact of these efforts, we use the Lost Time Injury Frequency (LTIF). In 2018, this was 2.36 which is an improvement compared to 2.53 in 2017. Starting in 2019, we will replace LTIF as our key performance indicator (KPI) for safety with Total Recordable Incident Rate (TRIR) as it counts all incidents, not only the Lost Time Injuries. In 2018, the TRIR was 3.1.

Lost Time Injury Frequency – TenneT [TenneT Integrated Annual Report 2018]

A number of studies have found that a safe workplace is a reliable workplace [Moore: 2005]. Every worker has the right to a minimal hazard work environment (to the extent practicable), and Asset Managers are frequently tasked by Asset Owners or the Asset Management program with adjusting maintenance tasks, project implementations, and other activities to improve work safety. Accidents and incidents are also often the subject of root cause analyses, which are a key part of continuous improvement. The British government has also estimated the costs associated with workplace illnesses and injuries. In Britain in 2017/2018, on average 582,000 workers were hurt on the job, while another 518,000 experienced a poor health episode they believe was triggered by working conditions. The costs associated with the injuries and illnesses are significant [UK HSE, see website http://www.hse.gov.uk/statistics/cost.htm].

Costs Due to Workplace Illnesses and Injuries (UK HSE, Costs to Great Britain of workplace injuries and new cases of work-related Ill Health – 2017/18 website at http://www.hse.gov.uk/ statistics/cost.htm)

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Regulators As Stakeholders

The regulator is almost always considered a key stakeholder as well. While the regulator often represents the public, they may also represent overall national policies, which are less directly involved with the public who are physically located near the assets. A good example from the US is the National Electric Reliability Corporation (NERC) requirements. All US utilities need to meet these requirements, which range from building operational plans to cybersecurity. Asset Owners are typically responsible for meeting the requirements, although the Asset Manager is usually charged with implementation. The NERC and similar asset requirements contain significant penalties for failure to comply, and the Asset Owner may impose penalties in turn on Asset Managers responsible for the noncompliance. Government agencies that deal with environmental, work safety, and other issues have similar guides, practices, or standards that the Asset Owner must “translate” into requirements for the Asset Manager. In some cases, the regulator has developed detailed requirements for the utility. For example, the UK has developed the RIIO regulatory strategy for utilities, which ties utility returns (customer billing in effect) to system performance, including risk management. This approach is discussed in Chap. ▶ 2. Practical Cases: Example 1: Enexis, Netherlands – Translation of stakeholder expectations in output measures The following example from Enexis of the Netherlands of its Value Creation Model, illustrates the involvement of Enexis’ various stakeholders (e.g., employees, customers, shareholders, and government) in value creation for the utility [TB 787, 2020]. Example 2: Enexis, Netherlands (from Enexis Annual report 2017) – What Stakeholders Consider Important Note that the values shown below for Enexis in this case, (this comment could be applied to any set of values) reflect the intentions of the company; but they may only represent a desired attitude rather than concrete actions in a specific area.

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Value Creation Model – Enexis [TB 787, 2020]

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Another example from Enexis of the Netherlands is of the Stakeholder Analysis from the evidence list table above. In this example, Enexis shows how it used the results of a stakeholder consultation to determine what its stakeholders consider to be important to them [TB 787, 2020].

Stakeholder Priorities – Enexis [Enexis Annual report 2017]

Example 3: Amprion GmbH, Germany – Stakeholder Analysis Amprion GmbH, Germany regularly performs analyses to understand the expectations of their stakeholders. The aim of such analyses is to understand the requirements of the stakeholders and to address these requirements within the company. The output of the stakeholder analysis can be taken into account for other elements of the Asset Management System (e.g., criteria for decisionmaking, planning the Asset Management objectives and stakeholder communication, etc.) The stakeholder analysis is carried out in several workshops with participants from departments such as corporate development, communication, and Asset Management. The procedure is as follows [TB 787, 2020]:

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Stakeholder Analysis Process – Amprion [TB 787, 2020]

The following diagram shows that Amprion has to consider a wide range of stakeholders.

Stakeholders – Amprion [TB 787, 2020]

Balancing stakeholder interests is a challenge. Therefore it is important to have an overview of the stakeholder requirements and to assess the requirements. The following graphic from Amprion shows this process.

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Stakeholder Requirements Assessment – Amprion [TB 787, 2020]

The result of the stakeholder analysis can be used as a basis for defining the criteria for decision-making, planning the Asset Management objectives, stakeholder communication, and much more.

4.6

Leadership: Organizational Roles and Responsibilities

Senior management is generally responsible for defining roles and responsibilities within the organization. This needs to be done properly to provide for the functioning of the utility and, specifically, for the performance of the Asset Management System. This effort must include assigning roles and responsibilities for developing, implementing, monitoring, and reviewing the Asset Management System, and that those roles and responsibilities are appropriately established, documented, and communicated within the organization. As with normal good management practice, senior management must ensure that the responsibilities are assigned to functions, roles, and competent individuals with appropriate authority, which is vital for an effective Asset Management System. Electric Transmission or Distribution companies ensure that the responsibilities and authorities for relevant roles are assigned and communicated within the organization by having: (a) An effective communication channel with top management (b) Clear definitions of AM roles and responsibilities and reporting relationships

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To ensure that the responsibilities, communication channels, etc., are documented and available widely throughout the company and externally, ISO55000 suggests the development of a Strategic Asset Management Plan (SAMP) that, at a high level, would outline these considerations. In addition, the utility will also develop an Asset Management Policies for definition and guidance. The following are examples of the Table of Contents used in a SAMP and in an Asset Management Policy [TB 787, 2020]. Example 1: TasNetworks, Australia – Illustration of the Content of a Strategic Asset Management Plan The following is an example of the table of contents of the Strategic Asset Management Plan (SAMP), a key document used in Asset Management.

Table of Contents, Strategic Asset Management Plan – TasNetworks [TB 787, 2020]

Example 2: Transpower, New Zealand’s electricity system operator – an Asset Management policy The following example presents the Asset Management Policy of Transpower. This document typically provides overarching guidance on what is to be included in the Asset Management program.

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Asset Management Policy – Transpower [TB 787, 2020]

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Risk Management

Enterprise Risk Management (ERM) was adopted by governments, government regulators, and major businesses over two decades ago as the preferred (mandated) method for evaluating and justifying investment decisions. Therefore, PAS55 and the ISO55000 series of standards require that management action must consider risk rigorously. In the past, companies have taken risk into account, but in an ad hoc fashion that results in nonoptimal strategies and tactics. In fact, review of industrial disasters, such as Chernobyl, Piper Alpha, and many others, shows that risks were often considered to be minimal or nonexistent. Risk involves the idea, expressed in previous chapters, that any action can have consequences, which can be favorable or unfavorable. These consequences have a probability of occurring. The combination of probability and consequences provides a metric to compare actions – ideally, if the analysis is done properly, lower risk decisions will be identified that are preferable to higher risk decisions. Asset management guidance suggests adoption of the requirements of ISO31000 “Risk Management” for risk planning purposes (see Chap. ▶ 8 for risk-based business case analysis methods for asset management decision-making). The following sections summarize the high level requirements from that standard that need to be considered in the context of the strategic asset management function. Operating an electric system grid involves several business and societal risks. The danger to the public and the workforce, the potential for lost customer and company revenue from outages, the potential for significant cost increases due to heightened environmental regulations are just a few examples of risks. Asset management, as part of the “action” from the Plan, Do, Check, Act, (PDCA) continuous improvement cycle, must evaluate risk as an element of the decision-making process. All alternatives, including the “Do Nothing” alternative, involve risk. For example, a common problem addressed by asset management professionals is the aging of equipment as described above in Chap. ▶ 4 previously. For instance, in a replacement evaluation, the analyst might consider the following risks: • What are the net present value of the capital and risk-based costs associated with leaving an aged asset in place for 5 years versus replacing that asset now or later in a planning period? (See Part 1 Chap. ▶ 8) • What are the risk-based costs of continuing with a conventional time-based asset maintenance policy versus the option of investing in monitoring technology to move to real-time condition-based maintenance? (See Part 2 Chap. ▶ 13) Making risk-based decisions is typically the responsibility of the Asset Manager within the tactical asset management function (Chap. ▶ 7). However, the Asset Owner, as part of the Strategic Management process, is responsible for establishing risk criteria and the company’s appetite for risk. The following graphic illustrates the division between the three levels of Asset Management in more detail [TB 422, 2010].

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S1 = T1 S2 = T2 S3 = T3

Strategic level Overall strategies

Objectives/ Target values

T4 = Backlog T3 = No. of injuries T2 = Availability T1 = Cost/Budget

Planning level Tactical decisions

Risk Indicators Data

O1 = Preventive maintenance down time O2 = Corrective maintenance down time O3 = No. of unplanned jobs / No. of planned jobs

Operational level Operational decisions

O4 = No. of performed jobes /No. of planned jobs O5 = No. of faults O6 = Maintenance costs O7 = Injuries O8 = Technical condition O9 = Energy not supplied O10 = Absentee rate

Examples of Data and Objective Flows [TB422, 2010]

5.1

Risk Appetite/Tolerance

Companies, like individuals, have a risk profile. Some are risk adverse, while others are risk seeking. Most utilities fit into the risk adverse category – decisions with a high risk of adverse consequences may be less desirable, even if the ultimate pay-out is higher, than an option with lower risks of such consequences. An Asset Owner established the following profile for the Asset Manager as shown in the figure below from the 2002 Paris Conference [TB309, 2006]. This profile is more appropriate for an investor-owned utility as the utility can take risks to gain performance. The second is from a state-owned utility (TenneT) that keeps risks within certain bounds to ensure that performance is within desired levels [TenneT Integrated Annual Report, 2018]. Note that the risk profile also impacts risk acceptance and insurance decisions, as discussed in the following sections below.

Sample of Risk Tolerance [TB309, 2006]

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Sample of Risk Appetite – TenneT [TenneT Integrated Annual Report 2018]

5.2

Risk Acceptance

Utilities use their risk tolerance profile to determine which option may be preferable and when to take action. In some cases, the risk associated with a situation may not rise to the level where any action is needed. When this happens, the utility is implicitly stating that the problem is less important, can be managed when it occurs, and that it accepts the current risks and the possible increase in risk that might occur if no action is taken at this time. However, many times the utility will face an unpleasant choice: a problem exists that should be addressed due to its risk, but the effort needed (in terms of cost, effectiveness, regulatory permitting, or other factors) to mitigate or eliminate the risk is considered too high. Under unusual circumstances, the risk may be considered to be decreasing over time or may be more appropriate, for budget or other reasons, to deal with at a later date. In these cases, the utility chooses to take no or limited action. This is referred to as “accepting the risk” associated with the problem. Given guidance on risk appetite, typically, the Asset Manager accepts these risks, rather than the Asset Owner. If the Asset Owner is not making the risk acceptance decision, the Asset Owner may wish to review the list of accepted risks to ensure that they meet the Owner’s internal criteria. When risks for a problem are accepted, best practice requires identifying the risks accepted, the alternatives rejected in favor of the option selected (usually taking no action, but other possibilities exist), and the authority taking responsibility for the decision.

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Risk Identification

In a properly implemented Asset Management program, the company has established clear alignment of asset management goals and key performance indicators. Ideally, every KPI represents a type of risk that the company is routinely evaluating, although in many cases several risks may be “rolled up” against a single KPI. The Strategic Asset Manager tracks the high level KPI, while the Tactical and Operational Asset Managers track in performance indicators that roll up to the KPI. Managers at every level may also conduct audits to identify specific risks and develop corrective action plans. This is most common for system reliability issues – for example, circumstances may exist where an asset failure may result in equipment damage, loss of service to customer(s), regulatory penalties, or even system voltage collapse. In power delivery today, these are typically evaluated from a deterministic, rather than a probabilistic or risk-based standpoint. However, the urgency of implementation of the corrective action should include evaluation of the risks associated with taking or not taking actions. Usually, the Strategic Asset Manager will review the processes used by the Tactical and Operational Asset Managers, but leaves individual project prioritization to the lower levels of management. Risks can be identified at a number of levels, from Strategic to Tactical to Operational. The section below presents more examples on risks identified and how they might be managed.

5.4

Risk Analysis: Risk Matrices

Evaluating risk involves applying a method that combines the probability of an outcome when an event occurs with its consequences. In many instances, the method involves a two-dimensional matrix that maps levels of probability on one axis and consequences on the other axis. The priority of the problem (and its solution) is determined by its location in the matrix. The following example is drawn from RTE (France). Using the processes similar to those described earlier in this chapter, RTE developed a series of business values. From these values, RTE determined four levels of severity (other companies may have more or fewer levels) for events. Note that these all represent “negative” risks, rather than opportunities. RTE, like most utilities, has developed a range of values for each level of severity. This has the advantage of eliminating the need for an exact value as well as providing the ability to use qualitative values for the severities. The following table represents the consequences for each event [CIGRE, TB 597, p. 70].

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Consequences for Risk Determination (RTE)

Consequences for each business value can be combined to create a single consequence value if desired. The other input to risk is the probability of failure. As with the consequences, RTE creates several levels, each with a range of probabilities. The probabilities are as follows [CIGRE, TB 597, p. 70]: – – – – – –

Improbable, meaning