Jukka Lassila

STRATEGIC DEVELOPMENT OF ELECTRICITY

DISTRIBUTION NETWORKS – CONCEPT AND METHODS

Thesis for the degree of Doctor of Science

(Technology) to be presented with due

permission for public examination and

criticism in the Auditorium 1382 at

Lappeenranta University of Technology,

Lappeenranta, Finland, on the 19th

of

December, 2009, at noon.

Acta Universitatis Lappeenrantaensis 371

Supervisor Professor Jarmo Partanen

Institute of Energy Technology

Lappeenranta University of Technology

Lappeenranta, Finland

Reviewers Professor Kimmo Kauhaniemi

Department of Electrical Engineering and Automation

University of Vaasa

Vaasa, Finland

Adjunct Professor Veli-Pekka Nurmi

Department of Electrical Energy Engineering

Tampere University of Technology

Tampere, Finland

Opponents Professor Kimmo Kauhaniemi

Department of Electrical Engineering and Automation

University of Vaasa

Vaasa, Finland

Adjunct Professor Veli-Pekka Nurmi

Department of Electrical Energy Engineering

Tampere University of Technology

Tampere, Finland

ISBN 978-952-214-872-8 ISBN 978-952-214-873-5 (PDF)

ISSN 1456-4491

Lappeenrannan teknillinen yliopisto Digipaino 2009

ABSTRACT

Jukka Lassila

Strategic Development of Electricity Distribution Networks – Concept and

Methods

Lappeenranta 2009 156 p. Acta Universitatis Lappeenrantaensis 371 Dissertation. Lappeenranta University of Technology ISBN 978-952-214-872-8, ISBN 978-952-214-873-5 (PDF), ISSN 1456-4491 Strategic development of distribution networks plays a key role in the asset management in electricity distribution companies. Owing to the capital-intensive nature of the field and long-span operations of companies, the significance of a strategy is emphasised. A well-devised strategy combines awareness of challenges posed by the operating environment and the future targets of the distribution company. Economic regulation, ageing infrastructure, scarcity of resources and tightening supply requirements with challenges created by the climate change put a pressure on the strategy work. On the other hand, technology development related to network automation and underground cabling assists in answering these challenges. This dissertation aims at developing process knowledge and establishing a methodological framework by which key issues related to network development can be addressed. Moreover, the work develops tools by which the effects of changes in the operating environment on the distribution business can be analysed in the strategy work. To this end, the work discusses certain characteristics of the distribution business and describes the strategy process at a principle level. Further, the work defines the subtasks in the strategy process and presents the key elements in the strategy work and long-term network planning. The work delineates the factors having either a direct or indirect effect on strategic planning and development needs in the networks; in particular, outage costs constitute an important part of the economic regulation of the distribution business, reliability being thus a key driver in network planning. The dissertation describes the methodology and tools applied to cost and reliability analyses in the strategy work. The work focuses on determination of the techno-economic feasibility of different network development technologies; these feasibility surveys are linked to the economic regulation model of the distribution business, in particular from the viewpoint of reliability of electricity supply and allowed return. The work introduces the asset management system developed for research purposes and to support the strategy work, the calculation elements of the system and initial data used in the network analysis. The key elements of this asset management system are utilised in the dissertation. Finally, the study addresses the stages of strategic decision-making and compilation of investment strategies. Further, the work illustrates implementation of strategic planning in an actual distribution company environment.

Keywords: Strategy process, electricity distribution business, long-term planning,

investment strategies, medium-voltage networks, supply reliability, regulation

UDC 621.316 : 621.3.027.5 : 620.9 : 657.424 : 65.012.23

List of publications

I. Lassila J., Viljainen S. and Partanen J. 2002. “Analysis of the benchmarking

results of the electricity distribution companies in Finland.” In Proceedings of

the IEEE Postgraduate Conference on Electric Power Systems. Budapest,

Hungary.*

II. Lassila J., Viljainen S., Honkapuro S. and Partanen J. 2003. “Data Envelopment

Analysis in the benchmarking of electricity distribution companies.” In

Proceedings of the CIRED 2003, International Conference on Electricity

Distribution. Barcelona, Spain.*

III. Lassila J., Honkapuro S., Viljainen S., Tahvanainen K., Partanen J., Kivikko K.,

Antila S., Mäkinen A. and Järventausta P. 2005. “Power Quality Factors in

Efficiency Benchmarking.” In Proceedings of the CIRED 2005, International

Conference on Electricity Distribution. Turin, Italy.*

IV. Lassila J., Honkapuro S. and Partanen J. 2005. “Economic Analysis of Outage

Costs Parameters and Their Implications on Investment Decisions.” In

Proceedings of the IEEE PES 2005 General Meeting. San Francisco, CA USA.

V. Lassila J., Honkapuro S. and Partanen J. 2006. “Distribution Network

Investment Strategies in the New Business Environment.” In Proceedings of the

IEEE PES 2006 General Meeting. Montréal, Canada.

VI. Lassila J., Kaipia T., Partanen J., Järventausta P., Verho P., Mäkinen A.,

Kivikko K. and Lohjala J. 2007. “A Comparison of the Electricity Distribution

Investment Strategies.” In Proceedings of the CIRED 2007, International

Conference on Electricity Distribution. Vienna, Austria.

VII. Lassila J., Kaipia T., Partanen J. and Lohjala J. 2007. “New Investment

Strategies in the Modern Electricity Distribution Business - Reliability in the

Long-Term Planning.” In Proceedings of the IEEE PES 2007 General Meeting.

Tampa, FL USA.

VIII. Lassila J., Tanskanen A., Lohjala J. and Partanen J. 2009. “Unbundling of

Operation and Network Development Activities in Electricity Distribution.”

International Journal of Energy Sector Management. Volume 3, No. 4, 2009,

pp. 383–405.

*) Published also in Research Methodology on Data Envelopment Analysis (DEA). Mantri, J. B. (Ed.). Boca Raton, FL USA: Universal-Publishers.

Acknowledgments

The results of this doctoral thesis are mainly based on the research projects carried out during

the years 2001–2009 at the Laboratory of the Electricity Markets and Power Systems, Institute

of Energy Technology (LUT Energia) at Lappeenranta University of Technology. Several

people have contributed to the work, and it is a pleasure to thank all those who have made this

thesis possible.

First, I owe my deepest gratitude to my supervisor Professor Jarmo Partanen for his guidance,

encouragement, valuable contribution during this work and long-time support on my research

path.

I would also like to thank my colleagues Mr. Tero Kaipia, Professor Samuli Honkapuro, Mr.

Juha Haakana, Mr. Pasi Salonen, Professor Satu Viljainen and Ms. Kaisa Tahvanainen for their

help and valuable ideas during various stages of my study. I wish also to thank Dr. Juha Lohjala

from Suur-Savon Sähkö Oy for working as an important link between researchers and

electricity distribution industry.

I thank the pre-examiners Professor Kimmo Kauhaniemi from the Department of Electrical

Engineering and Automation, University of Vaasa and Adjunct Professor Veli-Pekka Nurmi

from the Department of Electrical Energy Engineering, Tampere University of Technology for

their feedback and comments, as well as their genuine interest in the topic and their willingness

to engage in the pre-examination process.

Special thanks are reserved for Dr. Hanna Niemelä for her valuable assistance in the preparation

of this manuscript.

This thesis was financially supported by Ulla Tuominen Foundation, the Finnish Foundation for

Technology Promotion and the Lappeenranta University of Technology Foundation.

Finally, my sincerest appreciation goes to my parents Eero and Pirkko, my sisters Henna,

Annika, Anna-Maija and my brother Hannu for their time, energy and loyalty.

Lappeenranta, December 2009

Jukka Lassila

Contents

Abstract

List of publications

Acknowledgments

Nomenclature

1. Introduction ................................................................................................................... 13 1.1. Main objective of the work.................................................................................. 14 1.2. Outline of the work .............................................................................................. 15 1.3. Scientific contribution.......................................................................................... 16 1.4. Summary of publications ..................................................................................... 17

2. Introduction to strategic planning............................................................................... 21 2.1. Network strategy process..................................................................................... 23

3. Changes in the operating environment ....................................................................... 31 3.1. Ageing infrastructure ........................................................................................... 34 3.2. Regulation and ownership ................................................................................... 36 3.3. Quality of supply ................................................................................................. 41 3.4. Climate change..................................................................................................... 49 3.5. Environmental issues ........................................................................................... 51 3.6. Risk of blackouts ................................................................................................. 53 3.7. Scarcity of resources ............................................................................................ 58 3.8. Increase in material and labour costs................................................................... 59 3.9. Energy policy ....................................................................................................... 60 3.10. Distributed generation and smart grids................................................................ 62

3.10.1. Smart grids and electric cars ................................................................ 63 3.11. Technology development..................................................................................... 65

3.11.1. Network data systems and management of information...................... 65 3.11.2. Development of materials, working methods and automation ............ 66

3.12. Summary and conclusions ................................................................................... 67

4. Methodology and tools of strategic analysis ............................................................... 69 4.1. Drivers of the strategy process............................................................................. 72 4.2. Network technologies and potential surveys ....................................................... 73

4.2.1. 1000 V low-voltage technology........................................................... 73 4.2.2. Circuit recloser ..................................................................................... 75 4.2.3. Underground cabling, transfer of lines to roadsides, covered

conductors ............................................................................................ 81 4.2.4. Compensation of earth fault currents ................................................... 84 4.2.5. LVDC................................................................................................... 86 4.2.6. Remote-controlled disconnector .......................................................... 88 4.2.7. Interdependence between network technologies and

reliability .............................................................................................. 89 4.3. Calculation methodology for the analysis of long-term cost and

reliability effects .................................................................................................. 93 4.4. Description of the calculation system.................................................................. 95

4.4.1. Objectives and purpose of the system.................................................. 95 4.4.2. Initial data............................................................................................. 96 4.4.3. Calculation operations of the asset management system..................... 99 4.4.4. Determination of the network value .................................................. 100 4.4.5. Reliability calculation ........................................................................ 105 4.4.6. Determination of long-term costs in distribution system

operation............................................................................................. 110 4.5. Background information required in the process............................................... 113

4.5.1. Power flow calculation....................................................................... 113 4.5.2. Fault current calculation..................................................................... 116 4.5.3. Network age and condition data......................................................... 118 4.5.4. Reliability calculation ........................................................................ 120

5. Strategic decision-making .......................................................................................... 125 5.1. Strategy analyses................................................................................................ 126 5.2. Strategic decisions ............................................................................................. 130 5.3. Implementation of strategic decisions ............................................................... 131 5.4. Impacts of implementation ................................................................................ 135 5.5. Conclusions on strategic decisions .................................................................... 140

6. Conclusions .................................................................................................................. 143

References................................................................................................................................ 147

Appended publications I-VIII

Nomenclature

Roman letters

a, b outage cost factors (€/kW and €/kWh)

C cost

c unit cost

E energy

f fault frequency

i, I network component(s)

j electricity consumer

l length

n number

P power

p interest rate

t (life-, clearance, repair, reference) time

U voltage, outage time (unavailability)

x length of the network after the circuit recloser

Acronyms

AMKA Aerial bundled cable (low-voltage)

AR Autoreclosing

EMA Energy Market Authority

EU European Union

CAPEX Capital Expenditure

CEER Council of European Energy Regulators

CC Covered conductor

CCA Chrome copper arsenic

CHP Combined heat and power

CIS Customer Information System

CPI Consumer price index

DEA Data Envelopment Analysis

DAR Delayed autoreclosing

DG Distributed generation

DMS Distribution Management System

GDP Gross Domestic Product

GIS Gas insulated switchgear

HSAR High-speed autoreclosing

IEEE Institute of Electrical and Electronics Engineers

INV Investment

KAH Keskeytyksestä aiheutunut haitta, Customer outage cost

LTP Long-term planning

LV Low-voltage

LVDC Low-voltage DC

MAIFI Momentary Average Interruption Frequency Index

MV Medium-voltage

NIS Network Information System

NVE Norges vassdrags- og energidirektorat, Norwegian Water Resources and Energy Directorate

OH Overhead line

OPEX Operational Expenditure

PES Power and Energy Society (IEEE)

PQ Power quality

PV Present value (of the network)

RV Replacement value (of the network)

SAIDI System Average Interruption Duration Index

SAIFI System Average Interruption Frequency Index

SCADA Supervisory Control And Data Acquisition

SF6 Sulphur hexafluoride

SFA Stochastic Frontier Analysis

STYV Sähköntuottajien yhteistyövaltuuskunta, a cooperative commission of electricity producers

TKK Helsinki University of Technology

TJSA Toimittamatta jääneen sähkön arvo, cost of non-supplied electricity

TUT Tampere University of Technology

VTT Technical Research Centre of Finland

WACC Weighted Average Cost of Capital

13

1. Introduction

Strategic development of distribution networks plays an essential role in the asset management

in electricity distribution companies. Owing to the capital-intensive nature of the field and long-

span operations of distribution companies, the significance of a strategy is highly emphasised.

A well-devised strategy combines the best knowledge of the challenges posed by the operating

environment and the future targets of the distribution company. Challenges originating from the

operating environment are constantly evolving. The economic regulation, ageing infrastructure,

scarcity of resources and tightening supply requirements together with challenges created by the

climate change put challenges on the energy sector. On the other hand, technology development

for instance related to network automation and underground cabling together with an

opportunity to outsource certain activities assists in answering these challenges.

Introduction of regulation into the electricity distribution network business and the stepwise

changes in the regulatory model have generated understandable uncertainty in the field. The

distribution companies are trying to figure out how the traditional development principles

applied in the companies will reflect through the regulatory model to the financial result of the

company. In particular, the role of reliability of supply has significantly increased during the

past decade. Previously, the outages experienced by the end-customers did not have a direct

impact on the financial result of the company. Since then, regulation has been developed so that

the quality of supply, in the form of reliability of supply, has an effect on the company result.

An evidence of the obvious effects of the regulatory measures is related to the collection of

certain indices. Although distribution companies have compiled statistics on automatic

reclosings at a general level already in the 1980s, the regulator formalised the obligation to

notify automatic reclosings as late as in Finland in 2003. A few years after issuing this

obligation, the regulator included automatic reclosings in the economic regulatory model.

Distribution companies were aware of this and started to seek tools to cut down short

interruptions. The basic idea involved in the regulatory model to create artificial market

pressure is advantageous for the development in the field and in society in general; the

distribution companies have to search cost-efficient solutions to the long-term development of

the distribution networks. The regulatory model has to encourage such investments that

minimise the long-term costs caused to society. However, a challenge posed by the regulatory

14

model is the increasing intricacy and unpredictability of the business. Furthermore, the model

should take into account the individual differences between companies, simultaneously

remaining equitable and understandable.

The intensively developing operating environment forces the distribution companies to focus on

strategic development of their distribution networks. This doctoral dissertation aims at

developing process knowledge and establishing a methodological framework by which key

issues related to network development can be addressed. The management and owners of a

distribution company play a central role in drawing up the guidelines for network development.

It is of high importance that required information concerning the operating environment,

network assets and development needs is available for decision-making and that there are

suitable analysis tools for the purpose. The questions addressed in the strategy process1 are

essential both to the company management and the personnel responsible for the long-term

development work.

1.1. Main objective of the work

The main objective of this work is to develop methodology for strategic planning of electricity

distribution networks. In the development work, for instance changes taking place in the

operating environment, electrotechnical requirements, reliability issues, ageing of the

distribution networks and the needs of the end-customers, network owners and the distribution

company have to be taken into account. Typical strategy-level questions include for instance the

following: what are the objectives set for the development of reliability of supply, and what are

the effects of different development options, such as full-scale underground cabling, on the

price of distributed electricity and the owner’s return on investment. In this doctoral

dissertation, general methodology is proposed for addressing strategic questions related to

network development in distribution companies. The presented methodology provides means to

1 In the context of this doctoral dissertation, the noun ‘strategy’ in the compound ‘strategy process’ is used as a generic term, which is neutral with respect to whether there already exists some distribution network strategy in the distribution company under observation, or a new strategy is developed from scratch.

15

and answer these questions; however, the work does not determine which is the appropriate or

best strategy for the distribution company in a given situation.

The work concentrates on electricity distribution networks in rural areas in Finland.

Nevertheless, the strategic approach and methodology of the kind described in this study can, to

a certain degree, be applied to urban distribution networks also. Forecasting changes in the

operating environment and drawing up detailed development plans are outside the scope of this

doctoral dissertation. Development of optimisation algorithms for single investments is not

among the key targets in this work either.

1.2. Outline of the work

This doctoral dissertation is organised as follows: Chapter 2 provides an introduction to

strategic planning. The chapter introduces in brief factors related to the electricity distribution

business and describes the strategy process at a principle level. Further, the chapter determines

the subtasks included in the strategy process and presents the key questions related to the

strategy work and long-term network planning.

Chapter 3 delineates the key factors related to the electricity distribution network business that

have either a direct or indirect effect on strategic planning and long-term development needs in

the distribution networks. These include for instance the ageing infrastructure, economic

regulation of the distribution business, the network owners, issues related to the quality of

electricity, climate change and blackouts, and shortage of resources.

Chapter 4 introduces and describes the analysis methodology and tools developed in the study

in order to perform the cost and reliability analyses. The chapter focuses on determination of the

techno-economic feasibility of different network development technologies for instance with

respect to underground cabling, circuit reclosers and earth fault current compensation. The

feasibility surveys are strongly linked to the economic regulation model of the distribution

business described in the previous chapter, in particular from the viewpoint of reliability of

16

electricity distribution and allowed return. The chapter introduces the asset management system

developed as a tool for research purposes, the calculation elements of the system and initial data

used in the analysis; the key elements of this asset management system are utilised in this

doctoral dissertation. Chapter 5 addresses the stages of strategic decision-making from cost

and reliability comparison to prioritisation of renovation targets and compilation of investment

strategies. Furthermore, the chapter illustrates implementation of strategic planning on an actual

medium-voltage feeder. The purpose of the example calculations and results presented in

Chapter 5 is to illustrate how the methodology can actually be applied to the strategic

development of the network. Nevertheless, it is pointed out that the results cannot be

generalised as such, but each distribution network has to be considered individually.

1.3. Scientific contribution

The main contribution of this doctoral dissertation is the establishment of the concept of the

strategy process with associated tools for the long-term planning of electricity distribution

networks. The scientific contributions of the dissertation can be summarised as follows:

- Concept of strategy process:

interactive way of thinking and working in the distribution business involving numerous

cross effects and factors that vary over time.

- Calculation and analysis methodology included in the concept of strategy process:

within the concept, plenty of calculation methodology is required both for technical and

economic calculations; in this work, methodology required for the purpose is developed by

simultaneously utilising existing methods.

- Functioning of the concept of strategy process is verified by practical network

development work in an actual distribution network company environment.

By utilising the above contributions, a network planner will be able to analyse the effects of

strategies on the costs of electricity distribution business, reliability of distribution networks,

and distribution fees.

17

1.4. Summary of publications

This doctoral dissertation consists of eight publications. Publications I–III concentrate on

development of the regulatory model with a special emphasis on efficiency benchmarking.

Publication IV addresses the interaction between outage costs and investment decisions.

Publications V–VII focus on investment strategies and challenges posed by the operating

environment to the electricity distribution business. The author of this doctoral dissertation has

been the primary (responsible) author in all the above publications.

Figure 1.1 illustrates the publications relevant to this dissertation.

Price for outages through regulation

Outage costs

Outage costs as part of the regulatory model

Effects of outage costs on investment decisions

Calculation of return on investment

Determination of economic rationale for investments, Development strategies

Challenges of outsourcing

IEEE 2002 CIRED 2005CIRED 2003 IEEE PES 2005 IEEE PES 2006 Int. Journal of Energy Sector Management 2009

CIRED 2007,

IEEE PES 2007

Figure 1.1. Timeline of the selected publications constituting the basis for the doctoral dissertation.

Publication I Analysis of the benchmarking results of the electricity distribution companies in

Finland.

Publication I discusses the drivers set by the regulation model on the electricity distribution

business from the perspective of efficiency benchmarking. The publication shows that it is

possible to determine an actual price for the quality of electricity (reliability of supply) through

the regulatory model. Moreover, the publication introduces and highlights some key problems

related to the efficiency benchmarking method applied, such as unpredictability and inequitable

treatment of companies. The analyses showed that changes in the quality of supply did not

necessarily have any effect at all on the efficiency score calculated for a distribution company.

Further, the publication shows that the outage cost parameter applied in the efficiency

benchmarking does not describe the quality of supply to a sufficient extent and accuracy. In this

publication, the author has played a primary role in performing the sensitivity and efficiency

benchmarking analyses and determination of outage costs.

18

Publication II Data Envelopment Analysis in the benchmarking of electricity distribution

companies.

Publication II addresses the drivers set by the regulatory model and the efficiency

benchmarking between distribution companies. The publication shows that the regulatory

model can be developed further by using outage costs, instead of outage duration, as an

indicator of the quality of electricity. Application of outage costs in efficiency benchmarking

ensures a more equitable treatment of distribution companies, simultaneously promoting the

predictability of the regulatory model. In Publication II, the author has played a primary role in

development of the efficiency benchmarking.

Publication III Power Quality Factors in Efficiency Benchmarking.

Publication III focuses on outage costs as part of the regulatory model and assesses the weight

of different quality factors in the model. From the perspective of long-term development of

distribution networks, the outage costs (if applied in the regulatory model) should include both

short and long interruptions, their number and durations, and planned and fault outages. Special

attention has to be paid to the weights of different outage cost components (€/kW, €/kWh) to

ensure that no single outage type receives disproportionate value, or alternatively, is ignored

altogether. Should the outage costs be included in the regulatory model, the effects of outage

costs (and individual outage types) on the development of the distribution have to be

understood. In this publication, the author has played a primary role in assessment of the weight

of the outage cost component applied in the efficiency benchmarking model and the incentives

based on the quality of supply included in the regulatory model.

Publication IV Economic Analysis of Outage Costs Parameters and Their Implications on

Investment Decisions.

Publication IV concentrates on the effects of outage costs on investment decisions. The analyses

establish that outage costs can be applied both to the planning and operation of the distribution

networks and in the regulatory model (e.g. efficiency benchmarking). In the regulatory model,

special emphasis has to be put on determination of outage costs: setting a reference level is a

challenging task, as too short a reference history in outage statistics will result in large annual

variations in the outage cost level, whereas too long a reference history will cause the effects of

19

reliability investments to show slowly in the outage cost level. In Publication IV, the author has

played a primary role in assessment of the significance of parameter selection related to outage

cost calculation and reliability effects of network investments.

Publication V Distribution Network Investment Strategies in the New Business Environment.

Publication V discusses the challenges posed by the operating environment to the electricity

distribution business with special reference to reliability and ageing of distribution networks

and low investment levels. The publication assesses the effects of new and replacement

investments on reliability and development of the network value as well as various

combinations of efficiency benchmarking (such as OPEX alone, OPEX + PQ, OPEX + PQ +

CAPEX). Furthermore, the profitability of different investments has been considered from the

perspective of determination of allowed return. In Publication V, the author has played a

primary role in determination of factors describing different regulatory models and the

operating environment of distribution companies.

Publication VI A Comparison of the Electricity Distribution Investment Strategies.

Publication VI introduces and describes determination of the economic rationale for a single

network investment, such as transfer of lines to roadsides, application of covered conductor

technology and underground cabling. In the analyses, special attention is paid to the effects of

the cost development of different technologies on their economic feasibility. Further, the

publication includes cost analyses of different development options made for an actual example

network. The publication also summarises the effects of investment strategies on the

distribution fees paid by the end customers. In Publication VI, the author has played a primary

role in compilation of feasibility studies of different network technologies, and to the

development of tools applicable to the analysis.

Publication VII New Investment Strategies in the Modern Electricity Distribution Business -

Reliability in the Long-Term Planning.

Publication VII introduces the essential long-term development technologies for distribution

networks and the drivers originating from the operating environment. The issue has been

20

approached in particular from the aspect of reliability. Moreover, the publication includes cost

calculations based on an actual example distribution network. In Publication VII, the author has

played a primary role in assessment of drivers originating from the operating environment and

the cross effects involved in development planning.

Publication VIII Unbundling of Operation and Network Development Activities in Electricity

Distribution.

Publication VIII presents a framework for decision-making in utilities where unbundling

considerations are taking place. The publication analyses the implications of splitting a long-

term network planning activity from the organisation responsible for short-term network

operation activities. It was found out that colliding interests in the new business model can be

avoided if economic and technical targets are mainly set by the regulator for both network

development and operation activities. In particular, the publication approaches the risks of

unbundling of network planning and operative functions with respect to information flows. In

this publication, the author has played a primary role in the analysis of the drivers originating

from the operating environment, both from the viewpoint of operative functions and long-term

network development.

21

2. Introduction to strategic planning

Electricity distribution is undergoing dramatic changes. Supply of electricity, which for decades

was considered to be a fundamental element of modern society, has developed into electricity

distribution business and network asset management (Figure 2.1), and is now evolving towards

intelligent electricity networks. In the branch, this has meant a radical change from the

traditional mindset, in which appropriations for development of electricity distribution networks

were taken for granted, into optimisation-based investment policies and emergence of service

markets. Ageing of electricity distribution systems, increased demands set by society for the

quality of supply and owners’ expectations have created pressure for intense renovation of

distribution networks and renewal of the branch. The emergence of cost-based investment

strategies has created a need for the development of various new planning and optimisation

models.

Electric utility- Generation- Transmission- Distribution- Sale

Electric utility- Generation- Transmission- Distribution- Sale

- Financing arrangements

- Target setting- Network management

agreements

Power generation company

Power generation company

Transmission (grid) companyTransmission

(grid) companyDistribution

companyDistribution

company Sales companySales company

Network ownershipNetwork

ownershipAsset

managementAsset

management Service providersService providers

- Setting principles of operation (= strategy)

- Management of service agreements

- Equipment supplier- System supplier- Network operation- Construction- Measurement

Figure 2.1. From supply of electricity into network asset management.

Electricity distribution business is capital intensive by nature, and it is characterised by long

lifetimes of the network components. Nowadays, the operating environment strongly impacts

the ways of operation and the economic result of the electricity network operators (distribution

companies)2, even though, because of the monopoly position, competition does not put pressure

on the daily business (Figure 2.2). At present, the most essential driver, established by the

operating environment, is the official techno-economic supervision of the electricity distribution

2 In the context of this work, the terms ’network operator’ and ’distribution company’ are treated as synonyms.

22

business. This regulation sets the framework for the network operators, within which they have

to operate. Deviating from this framework may lead to economic losses. Within the framework,

a network operator is relatively free to operate the business.

It depends on the targets set by the company owners how collecting of return allowed by

regulation is taken advantage of in the company and how the owner supervises and participates

in the long-term network development. The owner views may have a strong influence on the

development of the distribution network, for instance with respect to reliability. The ongoing

climate change has also increased the field’s interest in reliability issues. It has been estimated

that the reliability of electricity distribution will suffer from the increased winds and

precipitation, if these changes are not seriously taken into account in the future network

structures. On the other hand, the general technical development has enabled cost-efficient

construction of more reliable distribution networks. Furthermore, national and international

energy policies also have an impact on the electricity distribution business, for instance from

the viewpoint of network loss considerations and distributed generation (DG).

ELECTRICITY DISTRIBUTION BUSINESSEconomic

regulation

Owners

Climate change

Energy policyQuality of electricity

Ageing infrastructure

Technical development

Increase in electricity

consumption

Human and material

resources

Figure 2.2. Electricity distribution business; operating environment.

In this doctoral dissertation, operating environment is mainly treated as a boundary condition

and a variable against which the strategic-level planning has to be reflected at regular intervals.

The dissertation does not aim at compiling models, by which the direction and magnitude of

changes as such could be assessed and predicted. The work focuses on investigating how

different drivers originating from the operating environment affect the electricity distribution

business, how these factors should be taken into account in network strategies, and how the cost

23

and network effects of a single factor can be analysed. Assessment of these effects is based on

total cost models, in which the investment needs caused by the above-mentioned drivers and the

development of the quality of electricity, and the company return are examined.

Considering the levels of planning, the dissertation concentrates on strategic-level network

planning. This means that the work does not include for instance optimisation algorithms for the

choice of conductor cross-section on an economic basis. Instead, the emphasis is on general-

level planning. In the developing electricity distribution business, good knowledge of general-

level strategic planning is a prerequisite of successful business.

OwnershipBusiness planning

Network development

planning

Network planning

Field planning

Construction management

Network construction

Operation and maintenance

Figure 2.3. Electricity distribution business: from ownership to maintenance.

The guidelines drawn up by the distribution company in the strategic-level network planning

are used as the basis for long-term planning. The results of long-term planning are further

applied to network planning, where the design principles are realised in field and work

planning.

2.1. Network strategy process

Because of the capital-intensive nature of the electricity distribution business, network asset

management plays a key role in the operation of an electricity distribution company. A

precondition for successful asset management is an appropriate and consistent network strategy.

A well-prepared and maintained strategy provides valuable and reliable information for the

management in decision-making. Thanks to a feasible and rational strategy, the company

management and other personnel have a clear picture of the principles according to which the

network is developed further.

24

Grünig and Kühn (2006, p. 85) state that all strategic decisions share the following

characteristics: “They deal with complex interrelationships, they occur at irregular intervals,

they are always unique in their scope, in their questions and in the framework of pre-conditions

to be met and they have a long-term influence on the fate of the company.” This describes well

also the significance and characteristics of a network strategy in the electricity distribution

business. Drawing up a network strategy is a multi-stage, iterative process. A successful

strategy process calls for a survey of the distribution company’s operating environment (Figure

2.4). The target of this survey is to determine which operational preconditions and regulatory

effects arise from the surrounding society and which from the company history and background.

Societal factors that have an effect on the progress of the network strategy work and the final

results are for instance the development of the economic regulation model for the energy sector,

requirements related to the quality of supply, ageing of networks, climate change, changes in

energy use, and for instance various environmental regulations. The contents of the strategy

also depend strongly on the background and objectives of the distribution company itself, such

as the present state and condition of the distribution network, available personnel and material

resources and the targets that the network owners have. The strategy work becomes even more

challenging because of the abundant information sources but also information that may be

unreliable, fragmented, and in some cases, contradictory or deficient.

A survey of the operating environment may take quite a long time at the beginning of the

strategy process; however, its importance cannot be underestimated. The techno-economic

choices made in the strategy work concerning the network asset development are based on

information obtained from this survey, and therefore the feasibility and profitability of choices

are highly dependent on the reliability of the background information. The survey and analysis

of the operating environment are carried out by the operative management of the company and

the personnel in charge of network planning and operation; thus, in practice by those people

who will eventually utilise the results obtained from the strategy process in their work.

25

Survey of the operating environment and

collection of initial dataStrategic analyses

Society- Development of regulatory models- Reliability and quality of electricity- Climate change (challenges posed by

weather phenomena)- Network’s susceptibility to blackouts

(standard compensations)- Environmental regulations (e.g.

preservatives) - Technology development (e.g.

telecommunications)

Development in the field- Development of network technologies- Service providers- Distributed generation- Electric cars (energy storages)

Distribution company- Network assets- Human resources, skills and knowledge- Owner expectations and objectives- Return and reliability targets- Challenges posed by the geographic location

of the company (climate, soil)- Development in the area of operation (loads)

Initial data of the analysis- Network data (topology, components) - Load data- Fault history

Which are feasible network strategies in practice?- Transfer of overhead lines to roadsides, covered conductors- Underground and overhead cables, cable ploughing- Network automation (remote-controlled disconnector substations,

circuit reclosers)- Light primary substations, light 110 kV lines- 1000 V technology

Is there techno-economic potential for the technologies?What are the cost effects of the technologies?What are the reliability effects of the technologies?

The analysis is carried out for actual network sections to get usable results. Compact analysis tools and new calculation methodology are required for the analysis of large network entities.

Owners’ objectives (return expectations, investment in network development)?

Which calculation parameters will be used?-Unit costs (network components, losses, outage cost values, OPEX)-Interest rate, lifetime, load growth-Fault rates, switching and repair times

Figure 2.4. Network strategy process: survey of the operating environment and strategic analyses.

A survey of the operating environment provides a foundation for the strategic analysis. This

analysis concentrates for instance on the following issues:

- Which are the most compelling factors driving network renovation (network age,

reliability, ownership issues, pressure from society)?

- What network development alternatives are there; what is their techno-economic

potential?

- What are the cost and reliability effects of different development methods?

- Which calculation parameters are used in the strategy process?

- What are the owners’ objectives, and what are the opportunities and tools provided by the

owner(s) for network development (return expectations, investment in network

development)?

26

Concerning the current state of the distribution system and the distribution company, the most

important question that has to be addressed first is which are the strongest drivers for network

development. Are these drivers arising from the high average age of the network, poor

reliability, changes in the owners’ objectives or other factors related to the operating

environment? In most cases, there is no single driving force, but the need for network

renovation and development is a sum of many factors. In the strategy process, different network

technologies are analysed, from which the development alternatives that are the most suitable

for the operating environment and long-term targets are chosen. Determination of the techno-

economic potential of different technologies calls for extensive network analyses on actual

network sections. The target of the survey on the techno-economic potential is to ensure that

there really are economic grounds for application of the chosen network technologies in a

sufficiently large scale. To this end, various tools have been developed to assess the network

and cost effects of development alternatives with adequate accuracy and reliability. Although in

the past few decades, various optimisation algorithms have been developed for optimal

dimensioning of network structures, some of these being still in use, these algorithms cannot be

used as such to get an overall strategic picture because of the large network mass involved.

These technology-specific selection tools (e.g. selection of conductor cross-section,

determination of the outage cost benefit of network automation, techno-economic comparison

of underground cabling and overhead lines) can only be used in the analysis of a single target

and the technical solutions chosen for it. Getting a strategic overall picture of different

development alternatives requires an analysis of the cost and reliability effects of different

technologies on a large network section. Planning of electricity distribution networks has been

addressed for instance in (Willis, 2004) and (Lakervi and Holmes, 1995). The long-term

planning principles presented in these works can be applied to subtasks of the strategy work, yet

they do not provide direct assistance to the basic questions of strategic network development.

The calculation parameters applied to the strategy work play a key role also when assessing the

economic feasibility and network effects of different development alternatives. The role of

reliability in particular has gained importance along with the adoption of outage cost

parameters. A single distribution company cannot decide which cost parameters are used for the

determination of outage costs, but the unit costs for outages are defined by the authority

(regulator). In the current regulatory model for electricity distribution business, the outage costs

are the same for all distribution companies, and they reflect an average Finnish electricity end-

27

user group. Thus, in the definition of outage costs, the chief task of a network operator is to

compile and provide the required reliability statistics. A network operator is responsible for

monitoring the development of the quality of supply and submitting the reliability statistics

required in the outage cost calculation to the regulator. However, these statistics are not

compiled only for the needs of the authority; long-standing and reliable fault statistics are useful

for a network operator to focus the development actions on those targets where they are needed

most. One of the targets of a network strategy is to establish conditions for cost-efficient

development actions. In addition to reliability data, the company has to observe the

development of its operating area in terms of changes in the number of electricity end-users and

electricity use. Long-term load growth forecasts play a key role in the determination of the

required transformation and transmission capacity and the optimal loss costs.

In the analysis stage of the strategy process, there has to be a clear picture of the challenges that

will burden the network in the future, and of how the different network technologies are able to

answer these challenges. In the strategy work, the network technologies are only roughly

outlined; a more detailed techno-economic selection is made together with the analyses of

delineated network sections. As a whole, the process is iterative and complex by nature. In

particular, the reliability and outage cost aspects involved complicate the analysis because of

the various cross effects between cost components and reliability. For instance, building a new

primary substation is shown in the company turnover as a lump-sum investment cost, but also in

the annual network operation, maintenance and outage costs. Further, when also efficiency

requirements set by the regulatory model are taken into consideration, the final cost effects of a

single investment and larger development alternatives become even more complicated. A basic

investment such as a primary substation is no longer an investment dictated by the technical

network boundary conditions alone, but the obligations and effects related to the investment

extend through different cost components into the entire distribution business of the company.

Achieving successful results in the strategy process requires good knowledge of the reliability

effects of different network technologies and the regulatory model, but also uninterrupted

communication with the owners. The strategic analysis produces guidelines about the network

technologies, owners’ objectives and the investment strategies applied to the long-term planning

in the company (Figure 2.5).

28

Strategic analyses

Long-term plan

Implementation of strategic decisions

Potential use of technologies (%)- Transfer of overhead lines to roadsides (25 %)- Underground cabling (10 %)- Remote-controlled disconnector substations, circuit

reclosers (1 pcs/feeder)- 1000 V technology (30 %)

Cost effects of the technologies- Transfer of overhead lines to roadsides (50 km/a, 1 M€/a)- Underground cabling (5 km/a, 250 k€/a)- Remote-controlled disconnector substations, circuit

reclosers (20 pcs/a = 250 k€/a)- 1000 V technology (50 km/a, 1 M€/a)

A long-term plan for the example area and the whole distribution company taking into account the strategic decisions made in the process.

How a single development technology e.g. underground cabling is implemented in practice?

- Underground cabling: starting from the feeder sections most vulnerable to faults, or from the oldest sections, or by proceeding from the substation downstream from the feeder

- Network automation:…

What are the effects of different development methods?

- Costs, reliability, distribution fee, allowed return

Strategic decisions

Reliability effects of the technologies fault duration rate reclosings

- Transfer of overhead lines to roadsides (x) x x- Underground cabling (x) x x- Remote-controlled disconnector

substations, circuit reclosers x/x -/x -/x- 1000 V technology (x) x x

Owners’ objectives- Reduction in SAIDI 20–40 %- Increase in the present value of the network from 45 to 50 %

Calculation parameters- Unit costs: x €/km, y €/pcs- Losses: 50 €/MWh- Outage cost values: EMA- Interest rate: 5 %- Lifetime: limits set by EMA (maximum)- Load growth: 1–3 %/a (by regions)- Fault rates: x pcs/100km,a (overhead line)…- Switching times: 60 min (manual), 10 min (remote) - Repair times: 4 h (cable), 2 h (overhead line)…

- Main technologies- Owner’s perspectives

(amount and schedule of investments)

Figure 2.5. Network strategy process: from strategic analyses to a long-term plan.

The network technologies that are chosen based on the strategic analysis and that are suitable

for the company’s operating environment are applied to the development planning for target

network areas. Now the cost and reliability benefits as well as application opportunities of

different technologies are specified in more detail. From the viewpoint of network structure,

loads and reliability, the selected example areas that represent actual network sections describe

well the whole operating area of the distribution company and thereby provide a good general

view of the applicability of development technologies to the whole operating range of the

company. As a result of the analysis, the suitable, most cost-efficient network development

technologies, the application potential of the technologies and large-scale cost and reliability

effects are determined for the network operating area in question. Should the development

alternative not meet the objectives set by the owners for instance with respect to reliability or

costs, this alternative can be excluded or redefined so that the set targets are met. If the

boundary conditions and targets determined at the beginning of the strategy process are met, it

29

is possible to make a strategic decision to include the development alternative in the long-term

development plans of the distribution network.

LANDBO

MASSBY

KALLBÄCK

MARTINKYLÄ

– Cabling and covered conductors

– Renovating overhead lines to roadsides

– Distributed protection: reclosers

– Remote-controlled disconnectors

– Low-cost 110/20 kV substations

– Low-cost 110 kV line

– 1000 V technology

– LVDC

– Energy storages

– Distributed generation

– Intelligent customer connections

??__ km/a __ units/a

Effects:- Reliability?- Age and condition?- Distribution fee?- Public relations?- Return?

??

Figure 2.6. Issues to be included and analysed in a general-level network strategy.

Before actual transfer of strategic decisions into the long-term network development, an

investment strategy is compiled including analyses how the different technologies are

eventually put into practice (e.g., in which order). For instance, underground cabling can be

carried out either by starting from those feeder sections that are most vulnerable to faults, or

from the oldest sections, or by proceeding from the substation downstream from the feeder.

These choices may have significant cost and reliability effects; in particular, depending on how

fast the reliability is improved by the investments made. The strategy process now continues so

that the chosen technologies are applied systematically in the long-term network planning in the

entire operating area of the distribution company. Thus, the strategy is incorporated into the

company practices.

In the strategic planning, the achieved results are concretised in long-term planning. Taking the

changing operating environment fully into account requires development of new planning

methodology and tools. Although planning methodology has been developed already from the

1970s and 80s onwards, for instance the arising reliability issues and the profound changes in

the operating environment have led to a situation where the above-mentioned specific planning

methods cannot be applied as such to the present-day network planning. As the electrification

process started in a large scale in the 1950s, and the loads were increasing, it was necessary to

develop the models from the viewpoint of load flow and loss control. Now, instead, the models

30

have to take into account in detail the effects of ageing networks and reliability, and thereby

their economic control effects. On the other hand, a strong increase in loads cannot be excluded

from the future development scenarios, as for instance electric vehicles entering the markets

will have a significant impact on the strategic planning and network structures. Although such a

development trend is not forecast for the very near future, because of the long lifetimes of the

network structures, it is necessary to take this option somehow into account already in the

present-day strategic planning. Further, distributed generation may have a strong regional

impact on electricity distribution networks. However, the issue is outside the scope of this

dissertation owing to its present minor role in electricity distribution networks.

The target of long-term planning is to determine the economically best solutions in terms of

network structure and the type and schedule of investments. To reach the target, the loads,

losses, voltage drops, earth fault and short-circuit currents and outage costs of different network

sections are calculated. Based on these calculations, the development needs in the network are

determined. Efficient long-term planning is based on a systematic planning process and

utilisation of methods that facilitate and promote the planning work. Long-term planning can be

considered to consist of a number of smaller subtasks that support the ultimate target, that is,

minimisation of the total costs of distribution network operations in the long term. For this

purpose, numerous cost optimisation algorithms have been developed for different tasks, such

as choosing an optimal conductor cross-section (a new conductor, reinforcement of an existing

line) and determination of the economic feasibility of underground cabling, using a covered

conductor or transferring a line to the roadside, or application of network automation (e.g.

circuit reclosers).

31

3. Changes in the operating environment

The business operations of electricity distribution companies are strongly dependent on the

operating environment. The main focus of the business is on maintaining and developing the

electricity distribution network. Because of the monopoly nature of the business, official

supervision of the business constitutes an essential part of the business planning. The network

assets of the distribution company may be spread over a very large geographic area, and

depending on the geographic location and network structures, they may be vulnerable to

environmental conditions, such as weather, particularly in rural environments. The boundary

conditions for the quality of electricity, set by the techno-economic regulation of electricity

distribution business, force the distribution companies to constantly develop their operations to

meet the challenges posed by the operating environment.

Evolution of society has reflected the need to develop the electricity distribution networks. The

increase in electricity use has followed the general economic growth. The electrification process

from the 1950s and 60s onwards enabled the introduction of various electric tools and

apparatuses in rural areas. The resulting increase in electricity consumption has forced the

companies to be aware of the loads on the network and to solve the problems arising from the

load growth. The electricity distribution companies also needed to have a good insight into the

development trends in society and thereby in the electricity use within their operating areas, and

plans for how the challenges posed by the changing environment are met. Although load growth

is no longer the major single factor directing the network development, awareness of changes in

the operating environment and the need for a development strategy are still paramount issues in

electricity distribution companies (Van Geert, 1997). As a matter of fact, the growth in energy

use can in some areas be slight or even negative. Although development has been rapid in the

field in the past few years, substantial changes can be expected in the coming years for instance

because of ageing networks (Welch, 2001), increasing demands for reliability, climate change

and introduction of distributed generation (Watson et al., 2001) and intelligent networks

(Ipakchi and Albuyeh, 2009). Hence, the traditional development needs based on

electrotechnical reasons are making way for new challenges.

32

There is a tendency that the passive role of electricity distribution business is turning into active

one (Woodman and Baker, 2008). Previously, the development in the field has followed the

general trends in the demands of society, and the field itself has not shown the way, nor has it

set trends for the development in society. Currently, the more active role of the business is

shown for instance in the market penetration of smart electric meters in remote metering (EU,

2006), (Houseman, 2005) and increased distributed generation (Watson et al., 2001); in the past

few years, considerable resources have been allocated to the research of this subject matter.

Although significant breakthroughs have not yet been made, the evolution of distributed

generation may make it an essential element in the electricity distribution systems. As DG

becomes more common, electricity distribution networks will be a genuine marketplace for

electricity production, transmission and use. Remote metering and bidirectional data transfer

will have a central role in the establishment of this marketplace. As a whole, the amount of

intelligence in the electricity distribution network will increase; this will mean faster and easier

adoption of new technologies compared with the opportunities provided by the present

electricity network infrastructure alone. Electric cars are an example of these new applications;

problems related to the entry of electric vehicles are discussed in more detail in section 3.10.1.

The changing needs of society have made the development of electricity distribution networks

an increasingly complex and demanding task. While in the early days of electrification the

target of the company was to build electricity distribution networks at a minimum investment

cost, various new cost elements and technical boundary conditions have now been introduced

into the optimisation task. These elements and boundary conditions have to be taken into

account especially in the strategic planning of networks.

In the process of electrification of rural areas, the target was to make a basic commodity

available all over the country. First, electricity was mainly used for lighting only; thus, the

power demand of a single end-user was not very large. Consequently, because of these

relatively small loads, the electrotechnical dimensioning of distribution networks was not

considered a key issue. Instead, the availability of materials determined the dimensioning

principles. In practice, the target was thereby to minimise the investment costs at the time of

construction. Later, when electricity became a source of energy in heating and large machines,

the limits of the transmission and transformer capacity of the existing networks became evident

33

by voltage drops and small voltage elasticity. Furthermore, the poor reliability of distribution

networks was shown by repeated supply outages. Poor reliability could be explained by

shortage of material; the conductor lengths had been minimised by drawing the lines directly

from the primary substations through forests to the distribution substations and from there

further to end-users. Moreover, underground cabling was rare because of its high costs. Because

of severe weather phenomena and snow loads, forests constituted a challenging operating

environment for electricity distribution and power lines.

The development of electricity distribution networks has been characterised by long lifetimes of

network components. For instance, the lifetimes of overhead lines are typically 40 to 50 years.

In the field, there have been two dominating trends in the long-term network development: In

the first development model, the key idea is to aim for maximising the network lifetime by

applying various ageing models for distribution systems (Bouford and Willis, 2005), (Hoskins

et al., 1998), (Datla and Pandey, 2006), (Hilber et al., 2005), (Birtwhistle et al., 2006) and

(Schneider et al., 2006). In the second model, the target is to take into account the owners’

objectives and challenges posed by the operating environment in an extensive and

comprehensive manner well ahead in the future. This model, however, is not about system

horizon planning (Fletcher and Strunz, 2007), but the direction of the network development is

adjusted annually in this approach.

In the 1980s, a massive need for distribution network renovations was expected to arise; this

assumption was based on estimates of the lifetimes of wood poles. Initially, it was estimated

that the overhead lines built in the 1950s and 60s would reach the end of their lifetime by the

end of the 20th century. However, these massive replacement operations could be postponed to

the 21st century, partly because the initial estimates for the actual lifetimes of wood poles had

been too pessimistic. It became evident that the pole replacements scheduled for the 1990s

could be put off for at least ten or fifteen years. The delay in replacement work can be said to be

partly due to profound changes in the electricity market. In the field, the liberalised electricity

markets and unbundling of electricity transmission and sale shifted the focus to coping with the

business challenges.

34

It is obvious that a postponed network renovation cannot be put off for ever. When wood poles

are reaching the end of their lifetime, the mechanical condition of a pole deteriorates to such an

extent that it can no longer be used for its purpose. Although replacement of a single pole is a

fairly simple task, at the company level, the large number of poles makes the renovation a

demanding job. In addition to shortage of material, there is a challenge to find enough labour

for planning and actual implementation of the renovation work. And because all the distribution

networks share the same problem of ageing networks, it is a nationwide issue to be dealt with.

The scale of the work can be illustrated by the financial value of the electricity distribution

infrastructure; the replacement value of the Finnish electricity distribution system was estimated

to be 13.6 billion euros in 2007 (Hänninen, 2008).

Because of the strong dependency on the operating environment, compilation of a network

strategy calls for an extensive analysis of this environment. The evolving technical and

economic regulation of electricity distribution business and increasing demands for reliability

together with the climate change and development of loads in the operating environment set

various boundary conditions and requirements for the network strategy; these have to be taken

into account at the very beginning of the strategy process. The starting points for the strategy

work may differ considerably between companies, even though there are certain common

features such as ageing infrastructure or scarce resources. In one company, the owners’ targets

may enable very fast development work in order to improve network reliability and to tackle the

ageing of network structures. In the other company instead, the owner’s conservative policy

concerning investment appropriations may limit the renovation to targets where the need is the

most urgent. Considering the present investment needs, a tight investment policy may make the

long-span network development a challenging process.

3.1. Ageing infrastructure

Extensive electrification of small towns and, in particular, rural areas took place chiefly

between the 1950s and 1970s. This process has been reported for instance in the following

national and international publications: (Lohjala, 2005), (Van Geert, 1997), (Welch, 2001),

(Brown and Humphrey, 2005), (Brown and Willis, 2006), (Li and Guo, 2006), (Hampson,

2001) and (Wijnia et al., 2006). With its problems of ageing and reliability, the electricity

35

distribution network infrastructure shares common features with other large infrastructures,

such as road and railway networks, water supply and sewer systems, and district heating

systems, which are all in need of replacement in the near future (ASCE, 2009), (Civil, 2003)

and (CIBC, 2009).

The age and renovation needs of a distribution network can be illustrated by the age data

concerning the wood poles (Figure 3.1) and transformers on the network. In particular, this

applies to distribution network companies in rural areas, where the network consists

predominantly of overhead lines. By investigating the age distribution of poles in the example

company we can see that the largest network investments took place in the example company in

the 1960s and 70s. This reflects the situation also elsewhere in Finland and in the Scandinavian

operating environment in general. The electrification of rural areas was by no means a minor

task; the scale of the work can be illustrated by the fact that even at present, overhead lines,

which serve as an example of the Finnish electricity distribution network infrastructure in rural

environments, account for 90 % of the total length of 134 600 km of medium-voltage networks.

Their financial value is high; overhead structures in rural areas accounted for about 7 billion €

of the total 13.6 billion € of the mass of property in the electricity distribution sector in 2007

(Hänninen, 2008).

0.0 %

0.5 %

1.0 %

1.5 %

2.0 %

2.5 %

3.0 %

3.5 %

4.0 %

4.5 %

5.0 %

1950 1954 1956 1958 1960 1962 1964 1966 1968 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

Pe

rce

nta

ge

va

lue

of a

ll w

oo

d p

ole

s

Figure 3.1. Age distribution of wood poles in a Finnish electricity distribution company (Lohjala, 2009).

36

For the whole electricity sector, simultaneous ageing of the entire distribution network

infrastructure creates a challenging operating environment; however, the arising renovation

needs can also be seen as an opportunity for introduction of new network solutions.

Strategically relevant issues in the future renovations will be: how the network infrastructure is

renewed, how the renovations are scheduled for the coming years, and which technologies are

favoured in the process. The renovation methods will be strongly influenced by the regulation

of the electricity distribution business and the company owners’ objectives.

3.2. Regulation and ownership

In the electricity distribution business, an essential factor associated with the operating

environment is regulation, in other words, supervision of electricity distribution business.

Because an individual electricity end-user can have only a minor impact on the operation of a

distribution company that has a monopoly position in the market, there is regulation to

safeguard the rights of an ordinary electricity user. The authority supervising the electricity

distribution business collects both technical and economic data and determines whether the

company operation has been in compliance with the Electricity Market Act. The increasing and

more detailed regulation also ties up more and more company resources, and the more

complicated regulatory model makes it more difficult to assess the long-term cost effects of

different investments. A single investment, such as construction of a new primary substation,

has an effect on the reliability of supply, operational costs and the value of the distribution

network, and has thereby a direct impact on the allowed rate of return of the company. When

we add the general and company-specific efficiency requirements and the related complex

efficiency measurement models on top of this, we can see that determination of the final

benefits and drawbacks of different investments is a demanding task. The complexity of the

task is illustrated in Figure 3.2. The alternative investment types, a repair investment and a new

investment, are presented in the bottom left corner of the figure.

37

Existing outage costs

AllowedOPEX

(historical data)

Reference for outage costs

OPEX

Existing costs of outages

Allowed profit

Efficiencybenchmarking

(DEA/SFA)

Depreciations (Replacement

value/ life time of network)

Efficiencyrequirement

Quality reward

Quality penalty

Depreciations

Replacementinvestments

Investment for new capacity

Present valueof network asset

Replacement value of network asset

Length of network

Number of customers

Energy deliveredO = operational

activities

P = planning activities

E = environmental factors

o

p

p

o + p

p

o + p

E

E

E

p

p

Figure 3.2. Interconnections between power quality, outage costs and allowed rate of return in the Finnish

regulatory model (adapted from Honkapuro, 2008).

Regulation can thus be considered to have a strong effect on the electricity distribution

business. Regulation determines the maximum return for a certain network solution, which has

an influence on the rate of return on network business and the distribution fees. The current

regulatory model provides good incentives for network renovations. In particular, the role of

reliability has gained significance after the adoption of outage costs in the model. In the current

regulatory model, both short and long supply interruptions are taken into account. Further, both

the planned and fault outages are included in the regulatory model. Although owing to their

duties, the distribution companies have always been interested in the reliability of electricity

supply, reliability had no direct cost effects on the profit and loss (return) of a distribution

company in the early regulatory models. The first cost effects were introduced to the Finnish

regulatory model as the Data Envelopment Analysis (DEA) methodology was applied to the

efficiency measurement in 2001 (EMA, 2001). The efficiency measurement was based on five

parameters (operational costs, duration of outages experienced by customers, network length,

number of customers and energy transferred) (Korhonen et al., 2000). The efficiency score

calculated by the DEA method had an impact on the operators’ obligation to reduce their

operational costs. Although the effect of single factors employed in the DEA method varied

considerably between operators and the predictability of the model was low, a link was

unintentionally established between the quality of supply (reliability) and the economic result

(Lassila et al., 2003b). Since then, the regulatory model has been developed further several

times (Partanen et al., 2002), (Lassila et al., 2003a), (Järventausta et al., 2003), (Partanen et al.,

38

2004), (Viljainen et al., 2004) and (Honkapuro, 2008). The target of the amendments has been

to remove ambiguity and to clarify the role of the quality of supply in the regulatory model. The

main features and effects of the regulatory models for different regulatory periods are presented

in Table 3.1. The role of reliability in the model is discussed in more detail in section 3.3.

Table 3.1. Main features and effects of the regulatory models in different regulatory periods (adapted from Honkapuro, 2008).

Time

period

Main features of the regulatory model Drivers

–2004 • Allowed return = PV * WACC • Reasonable depreciation costs = Average of three

years’ investments • OPEX and outage time in DEA benchmarking

- No penalties for inefficiency

• Return on all investments - Investments can be financed by funds generated from operations

• Some investments may have an efficiency bonus

• However, opportunities for incremental return are slight

2005–2007

• Allowed return = PV * WACC • Reasonable depreciation costs = straight-line

depreciations (= replacement value/lifetime) • Determination of the network value by standard costs • General efficiency target focusing on OPEX

• Return on investments still certain • Incremental return on efficient investments

(actual cost below standard price) • Obligation to reduce OPEX

2008–2011

• Allowed return and depreciations as above • Outage costs, OPEX and straight-line depreciations

included in efficiency benchmarking • Common and company-specific efficiency targets for

OPEX • Outage costs have an effect on allowed return (quality

incentive and efficiency benchmarking) • Standard compensations have an effect on allowed

return

• Investments may also have negative effects (straight-line depreciations in efficiency benchmarking)

• Strong incentives for quality improvement (on the other hand, penalties for reduced quality)

• Economic significance of blackouts emphasised

The regulatory model impacts the network investments not only through the reliability and

outage cost benefits provided by the investment; depending on the nature of the investment, it

may also affect the amount of allowed return determined for the company. If a completely new

network section is built or network capacity is increased, the investment is defined as a new

investment. A new investment increases the replacement value of the network and thereby also

the annual straight-line depreciations that are defined from the replacement value by the

lifetimes of network components. Adding new network components lowers the average age of

the network and increases the present value of the network. This in turn has a positive effect on

the allowed rate of return. Straight-line depreciations determined from the replacement value

make it possible to collect capital from the customers even though the present value of the

network had collapsed because of the high average age of the network. The term ‘replacement

39

investments’ refers to a situation where a network component is replaced with a new similar

component without causing changes in the capacity or replacement value of the network. A

replacement investment lowers the age of the network when the old component is removed

from the network. This change is shown in the present value of the network and in the allowed

rate of return. The replacement value or straight-line depreciations, however, are not influenced

by replacement investments.

For the long-span electricity distribution business, the rapidly developing regulation constitutes

a risk known as ‘regulatory risk’. Until now, regulation has been characterised by low

predictability and uncertainty. Essential questions that remain open are for instance: what will

happen after the present regulatory period, how is the quality of supply weighted, and which are

advisable investment targets for the distribution companies? Will the regulations on standard

compensations be tightened even further or will the long supply interruptions be “banned”

altogether?

Generally speaking, the regulation of the electricity distribution network business is being

intensified in Europe. General targets of regulation are to intensify the operation of monopoly

operators, to reduce the monopoly power of operators and to establish an artificial market. The

regulation of costs and quality of supply is emphasised; however, the recent long and extensive

supply outages have brought up a justified concern about maintaining sufficient investment

levels. Abrupt stepwise changes in regulation cause considerable changes in the business

environment of distribution companies. If these changes are repeatedly introduced within a very

short period, this may at worst lead to a state of stagnation, where the operators concentrate on

waiting for the regulator’s next move without any intention to develop the operations in the

long term. To ensure an incentive for long-term development, the strategic targets of regulation

have to be clear and consistent. Regulation is a continuous process, and thus, the regulatory

models will evolve and change; despite this, the regulatory signals have to be continuous. The

regulator has to be able to outline the changes that are to be expected a few years in advance so

that the operators have enough time to prepare for changes. If the regulation sets more detailed

company-specific targets for cost efficiency and quality of supply for the distribution

companies, it will be even more important for the operators that they are informed of the

evaluation criteria well in advance.

40

Hence, regulation has a strong impact on network development. How the regulatory effects are

manifested in the long-term network development depends on the ownership structures of the

network company. Depending on the targets the owner has set for collecting return, the owner

may either hold back or speed up the network development. It is the owner’s responsibility to

draw up a network strategy that determines the guidelines for distribution pricing, use of profit

and the level of quality. These are all key elements in the implementation of strategic planning.

Alternative models for collection and use of return are

a) The owner allows a raise in distribution fees required for network development,

however, does not collect this return but directs it to network development

b) The owner allows a raise in distribution fees, but takes the return

c) The owner requires that the distribution fees are kept at the present level, but directs

the return to network development

d) The owner requires that the distribution fees are kept at the present level and collects

the maximum return

In the two first alternatives, the owner takes full advantage of the limit that the regulator has set

for the maximum allowed rate of return by allowing a raise in prices. In the two latter

alternatives, the owner wants to keep the present price level.

Although regulation adds to the obligations and workload of a distribution company for

instance because of the data required to describe the operation of the company, the situation

cannot be regarded as a burden only. When considering from the network strategy viewpoint,

we can see that, to a large extent, the data required by the authority are such that the operator

has to gather anyway in order to be able to develop its operations. Hence, the data are not

collected for the authority only but to make sure that all the essential information required in the

strategic planning is available to support decision-making. Table 3.2 provides some examples of

the data gathered by the authority; the table also shows how this data can be applied to the

strategic development of the operations by the distribution company.

41

Table 3.2. Background data gathered by the regulator and application targets of these data in the development of the operations of an electricity distribution company.

Data gathered by the regulator Application target in strategic planning

Network components: number, age and lifetime data

Basic data applied to the analysis of the present state of the electricity distribution network and future investment needs

Annual investments General view of the network development history

Outage statistics Survey of the present quality level and possible problems in quality, allocation of renovation investments

Paid standard compensations Standard compensation costs with the present network, used as initial data for instance when analysing the effects of blackouts and network development needs

Financial statement information Some of the data applied to the analysis of the cost level of the present network

3.3. Quality of supply

Quality of supply is one of the key issues in electricity distribution network business. For

instance, monitoring schemes for continuity of supply are taking place in over 20 European

countries (CEER, 2008). From the regulatory perspective, the aims of quality control include

measuring actual and perceived levels of quality, promoting continuity improvement and

ensuring good continuity levels to consumers (CEER, 2005). In this work, the term ‘quality of

supply’ refers to the reliability of operation of the electricity distribution system. In the early

days of electricity distribution, unlike today, the quality of supply was not among the primary

questions. Shortage of materials forced to favour simple and straightforward solutions in

network planning and construction. This, in turn, led to line routing and network structures that

were challenging from the network reliability point of view. The interest in reliability issues

awoke in the 1970s; those days, the first reports were published on the harm caused to

customers by interruptions in the electricity supply (Billinton and Grover, 1975). Such

extensive customer surveys made it possible to assess the economic effects of outages, which

brought an entirely new, comparable element to network development. For the first time, an

outage cost element was introduced along with investment and outage costs. In Finland,

electricity end-users were interviewed for the first time in 1978 by Sähköntuottajien

yhteistyövaltuuskunta (STYV), a cooperative commission of electricity producers (STYV,

1979). The results of the survey were published in the report ”Selvitys toimittamatta jääneen

sähkön arvosta (TJSA)” (Report on the value of non-distributed energy). Ten years later, in

1988, a cooperative body Ryhmä 10, which consisted of the largest distribution companies,

42

made a survey on the harm caused to the customers by outages, and introduced a new term,

‘keskeytyksestä aiheutunut haitta’, KAH (customer outage cost), which later on established

itself as one of the key terms in the field. After this, an interview survey was conducted between

1992 and 1993 by VTT Energia (VTT Technical Research Centre of Finland), financed by the

Nordic Council. The survey was addressed to customers of 28 electricity distribution network

companies in Finland, Denmark and Iceland (Lemström and Lehtonen, 1994). The most recent

Finnish survey on outage costs in electricity distribution networks was carried out in 2005 by

Helsinki University of Technology (TKK) and Tampere University of Technology (TUT)

(Silvast et al., 2005). Figure 3.3 illustrates how the valuation of costs has developed in the past

three decades. Although there is an evident connection between the extent of outage costs and

the general increase in welfare, the outage cost values in the outage cost surveys of the past

decades have not increased at the same rate as the gross domestic product (GDP).

Consumer price index (CPI)

Electricity consumption

Gross domestic product (GDP)

GDP/electricity consumption

Households

Agriculture

Industry

Public

Services

Inde

x

Figure 3.3. Development of outage cost values and different indices between 1978 and 2004 (1 = 100 %;

1978) (Silvast et al., 2005).

Considering the quality of electricity, a challenge to the field was that although the indirect and

direct economic effects of outages were recognised already in the 1970s, the outages had no

direct effect on the actual business operations and investment considerations of electricity

distribution companies. An electricity end-user could of course complain about poor quality of

supply directly to the distribution company or the authority, but eventually, progressing the

matter was left to the distribution company. The authority had no incentives or penalties at its

disposal for the distribution companies to make the companies to be more active in the issue.

The practices associated with the development of reliability varied considerably between

43

companies. According to the results of the above customer surveys, the customers’ valuation of

uninterrupted supply has gained increasingly more importance over the years. According to the

most recent survey, a rough estimate is that the outage cost value has doubled in ten years.

Liberalisation of electricity markets and development of regulation promoted the recognition of

the role of reliability in the business of a distribution company. In the 21st century, along with

the overall development in society, the quality of supply (in particular reliability) has become

more and more important. The role of quality is gaining significance in the economic

regulation, and consequently, reliability issues will be increasingly emphasised in the

investment strategies. The first Nordic experiments on including outage costs in the regulation

of distribution companies took place in Norway in 2001 (Langset et al., 2001). In the regulatory

model, outage costs became part of rate-of-return regulation. Based on historic data, a target

level was set for all distribution companies; exceeding this level caused a penalty, whereas

going under the level was rewarded. In Finland, quality of supply was included in regulation in

the form of outage duration in 2000. Those days, outage duration (long supply interruptions)

was introduced as a parameter in the calculation of efficiency scores between distribution

companies. It soon became evident that using interruptions as an environmental factor involved

a problem that was shown by a biased treatment of companies in the calculation of efficiency

scores. The analyses showed that changes in the quality of supply did not necessarily have any

effect at all on the efficiency score calculated for a distribution company (Lassila et al., 2002).

As a consequence, the model was developed by abandoning outage duration as a parameter and

introducing a new outage cost model. This way, the role of electricity quality as an insignificant

factor was considerably reduced (Figure 3.4) (Lassila et al., 2003b).

44

0

10

20

30

40

50

60

Operational costs Quality of supply Distributed energy Netw ork length Customers

Dis

trib

utio

n co

mpa

nies

Original DEA model

Developed DEA model

Figure 3.4. Number of companies having insignificant factors in inputs. In the original DEA model,

quality of supply was measured as the total time of interruption (sum of long supply interruptions) and it

was a separate factor in the model. In the developed DEA model, quality of supply is not a separate factor.

It is taken into account in the input of the developed DEA model by adding it to operational costs (Lassila

et al., 2003b).

The regulatory model was developed further by including more and more detailed information

about the quality of supply in the calculation of efficiency scores. In addition to outage

duration, the quality of electricity, in the form of outage costs, included outage rates of long and

short outages as well as rates and durations of planned work outages (Lassila et al., 2005b).

From society’s perspective, the quality of supply and interruptions have a significant economic

impact. It has been estimated that for instance in Norway the annual economic harm caused by

long electricity supply outages has varied from 350 to 550 MNOK/a (42–66 M€/a) between

2001 and 2008 (NVE, 2009). In Finland, this economic harm was estimated to be 116 M€/a

(Paananen, 2008) for all distribution companies in 2006. When the extent of this harm is

compared with the operational costs of operators (340 M€/a) and with the annual investment

rate of 330 M€/a determined from the replacement value of the distribution network, we can see

that the outage cost component is a significant factor in the regulatory model (Paananen, 2008).

For a single electricity customer (total 3.1 M customers), the average annual outage cost was 37

€/customer,a in 2006. Other examples of European regulatory models in which reliability of

supply has some influence on the company income are for instance Italy, Ireland, Great Britain,

Hungary, Portugal, Sweden and Estonia (Losa and Bertoldi, 2009).

45

Table 3.1 demonstrates that the role of the quality of electricity, that is, reliability of supply, has

gained significance over the past few years. From the perspective of distribution network

development, the main factors relating to the quality of supply in the present regulatory model

can be presented as shown in Figure 3.5.

Change in outage costs

Change in quality incentives

Efficiency benchmarking

Change in efficiency score

Change in allowed return

Figure 3.5. Effects of changes in outage costs.

Quality incentive

A quality incentive is created, when actual outages and outage costs are compared with the

company’s historic data on reliability, that is, with a reference level. An improvement in

reliability increases the return of the company, while degrading reliability has an opposite effect

on the return thereby constituting a strong economic incentive for the quality of supply and

development efforts.

Efficiency benchmarking

Distribution companies are compared with each other by employing Data Envelopment

Analysis and Stochastic Frontier Analysis. The quality of supply is included in this efficiency

benchmarking through outage costs. Reduction of outage costs has a positive effect on the

efficiency score thereby increasing the allowed return of the company. In practice, the

efficiency score increases if the total costs reduce in proportion to efficient cost level.

Standard compensations

The term ‘exceptional events’ (major storms) is widely used all over Europe, but the term is

applied to classify very different kinds of situations in different countries. In Finland, from the

beginning of September 2003, the distribution companies have been obliged to pay standard

46

compensations to their customers, if the customer has experienced an interruption of supply that

has lasted at least 12 hours (Electricity Market Act, 2003). The amounts of the standard

compensations of the annual system service fee are:

- 10 % if the duration of the interruption has been at least 12 but less than 24 hours,

- 25 % if the duration of the interruption has been at least 24 but less than 72 hours,

- 50 % if the duration of the interruption has been at least 72 but less than 120 hours, and

- 100 % if the duration of the interruption has been at least 120 hours.

The maximum amount of the standard compensation because of an interruption of the system

service is however 700 €/a per customer. Contrary to almost all other European countries,

exceptional events are not excluded from compensation payment in Finland (CEER, 2008).

Standard compensations are included in the controlled OPEX, and thus, long supply

interruptions have a direct effect on the company return and thereby on the efficiency target for

the next period. Figure 3.6 illustrates the penalty structure of the Finnish electricity distribution

business regulation model by the variation of interruption duration. The case feeder has 300

customers (10 MWh/customer) and the distribution fee is 5 cent/kWh. Penalties for outages of

excessive duration (> 12 hours) are based on the limits presented above in this chapter. It is

assumed that the whole feeder is without electricity.

0

20 000

40 000

60 000

80 000

100 000

120 000

140 000

160 000

1 6 12 18 24 30 36 42 48 54 60 66 72 78 84 90 96 102 108 114 120 126 132 138

Duration of supply interruption [h]

Inte

rru

ptio

n c

ost

s (o

uta

ge

co

sts

an

d s

tan

da

rd

com

pe

nsa

tion

s) [€

]

Standard compensation

Out

age

cost

24–72 h

12–24 h

72–120 h

> 120 h

Annual income

Figure 3.6. Penalty structure in the Finnish electricity distribution business regulation model. The figure is

based on the example feeder (300 customers, 10 MWh/customer and 5 cent/kWh).

47

The economic effect of the outage cost component depends on how close to the limit set for

allowed return the distribution company is operating. At present, the effect of customer outage

cost may be at maximum 10 % of the allowed return calculated for the company. If the

accumulated previous customer outage costs exceed the maximum limits for the year in

question (“customer outage cost cutter”), the customer outage cost does not have a direct

economic effect. On the other hand, if the accumulated outage costs remain clearly below the

maximum level, the customer outage cost has an effect as illustrated by the outage cost curve in

Figure 3.6. After 12 hours from the occurrence of the outage, in addition to customer outage

costs, standard compensations start to accumulate for the company.

In Hungary, Portugal and Italy (Fumagalli et al., 2007) and in Canada (Billinton and Pan, 2002),

a reward/penalty structure has been suggested to be applied to the regulation of the distribution

companies (Figure 3.7). Large annual natural deviations are taken into account in the regulatory

model by allowing a certain dead zone for each company; changes in the reliability indices

remaining within this dead zone do not have an effect on the rewards or penalties paid. A

maximum level is set for both the rewards and penalties to ensure the reasonableness of the

system.

Figure 3.7. Reward/penalty structure (Fumagalli et al., 2007).

Although there is an obvious need for an outage cost component in the regulatory model,

uncertainties related to the use of this component should be recognised. Despite the fact that the

48

quality indices SAIFI, SAIDI and MAIFI3, on which the calculation of outage cost is based, are

simple and unambiguous, the reporting practices related to the compilation of statistics vary

considerably between distribution companies. For instance, surveys carried out in the U.S.A. in

1990 and 1995 revealed that the distribution companies had no uniform practices relating to the

compilation of outage statistics. Although many operators collect IEEE-approved indices, there

is a great disparity in the actual calculation of indices in the companies (Warren et al., 1999). In

Europe, the use of different weighting methods for indices with the same term (SAIFI, SAIDI)

makes international comparisons difficult (CEER, 2009). This is a fact that may reduce the

usability of the outage cost component in the regulation of the electricity distribution business.

However, a study made in the Nordic countries shows that very versatile interruption statistics

are collected for different purposes. In all countries, the statistics are used both for the energy

sector’s own aims and for regulatory purposes (Kivikko et al., 2005).

As was shown in the previous chapter, the objectives of the owner have an impact on the

development of the distribution network. From the viewpoint of the quality of electricity, the

owner views strongly impact the aims set for the desired level of reliability in the distribution

networks and the schedule for reaching these aims. Alternative targets can be for instance

- Maintaining reliability at the present level

- Improving reliability in fast, cost-efficient and flexible ways, with the aim of minimising

total costs (investments, outages, operational costs)

- Improving reliability in the long term, with the aim of minimising total costs (investments,

outages, operational costs)

- Aiming at a distribution system that is immune to weather phenomena irrespective of cost

The role of reliability and the quality of supply is emphasised in the Nordic environment, which

is characterised by a high forest rate and overhead lines that are vulnerable to adverse weather

phenomena. In Finland, about half of the outages experienced by end-customers are caused by

3 SAIFI: System Average Interruption Frequency Index, the average number of interruptions per customer per annum, SAIDI: System Average Interruption Duration Index, the total interruption duration per customer per annum, MAIFI: Momentary Average Interruption Frequency Index, the total number of customer momentary interruptions (Standard IEEE 1366-2001).

49

trees falling on the lines (Finnish Energy Industries, ET, 2009). If the climate change increases

windiness, the amount of storms and swift temperature variations around zero degrees Celsius,

the problems related to reliability will definitely increase in forest areas. Simultaneously, as the

challenges of reliability are aggravated by the climate change, also the issue of quality is

emphasised among the electricity end users. This poses a challenge to the asset management

and long-term network development. In Figure 3.8, the annual outage statistics of an example

distribution company illustrate how the years differ from each other with respect to fault rate.

From the regulatory perspective, annual variations in reliability are challenging; the regulatory

model should react fast enough to the development actions carried out on the network, yet

simultaneously, the model should be able to filter out the annual natural variations.

Thunder

9 %Snow and ice loads

1 %

Trees falling because of

snow load

11 %

Other weather condit ions

5 %

Animals

6 %

Incautious tree falling

4 %

Incautiousness, external

persons

2 %

Erroneous operation or

installation

1 %

Structural fault

6 %Unknown

10 %

Other

1 %

Wind and storms

44 %

0

50

100

150

200

250

300

350

400

450

500

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Average

Num

ber

of p

erm

anen

t fa

ults

[fa

ults

/a]

.

Other

Unknown

Structural fault

Erroneous operation orinstallationIncautiousness, externalpersonsIncautious tree falling

Animals

Other weather conditions

Wind and storms

Trees falling because ofsnow loadSnow and ice loads

Thunder

Figure 3.8. Examples of the causes of outages experienced by electricity end-users in an example

distribution company.

Similar statistics on the causes of interruptions are compiled in most European countries

(CEER, 2008). This information is important for the regulators and is essential to enable

distribution companies to improve the continuity of supply.

3.4. Climate change

Climate change has had and will have a strong influence on electricity distribution. All the

effects are not known yet; however, the most obvious effects are an increase in extreme weather

phenomena such as storms and increased snow loads (European Commission, 2005). The

blackout risk caused by storms will be discussed in more detail later in this section. In addition,

the temperature increase will have an effect on electricity distribution business and pricing, as

50

the consumption of energy will decrease. The temperature increase will also result in longer

growing periods, which in turn will increase the need for pruning and cutting of trees in

overhead line networks. Measured both by extreme and average values, the temperatures will

increase both in summer and in winter (FMI, 2009a; 2009b). Although there will be an average

increase in temperature, it is also likely that the range of extreme temperatures will be wider.

This would also mean higher requirements for design powers on the electricity networks. Yet

another factor that has a strong impact on overhead networks is an increase in such weather

conditions in which the temperatures lie around zero degrees Celsius, which increases the

occurrence of severe snow loads on the distribution network. Milder winters will affect the

thickness of ground frost, which may cause unexpected problems for instance to guyed poles in

overhead networks.

Precipitation is predicted to increase in Finland, which softens the soil and reduces the strength

of ground. Soft soil hampers the use of equipment required in the maintenance and construction

of power lines. Further, because of soft soil, especially trees growing on hill slopes may fall

more easily on overhead lines. The possible rise in ground water level has an impact on

underground cabling, as the cables may not be able to withstand the stress caused by a

continuous contact with water. As a result of the rising ground water level, the electrical

conductivity of soil increases, thereby increasing also the risk of corrosion in the guy structures

of poles. Moreover, as a result of heavy rain, floods in cities are possible, if the rainwater

drainage system does not manage to remove water from the streets. In such situations, there is a

danger that water gets into the basements of buildings and causes damage to basement

distribution substations. Floods in cities may also damage underground cable networks and

distribution cabinets.

On the basis of the observed and predicted climate changes, we may state that the expenses of a

distribution company will increase while the income will decrease. However, regional

differences between distribution companies may be significant. In Finland, the temperature rise

caused by climate change is estimated to affect electricity consumption as shown in Table 3.3.

51

Table 3.3. Effect of temperature on energy consumption and peak power, 2016–2045 (Martikainen, 2005).

Change in electricity

consumption [%]

Change in peak power

[%]

Customer group

minimum maximum minimum maximum

Agriculture -1.7 -3.2 -4.4 -6.6

Residential, dual heating -3.4 -6.1 -6.8 -10.1

Department stores and shopping centres 0.5 1.2 0.0 2.4

Hotel and accommodation services -1.5 -2.8 -4.1 -6.1

Restaurants and cafés 0.2 0.6 0.0 2.2

Financial institutions and insurance companies 0.4 0.8 0.0 2.1

If the demand for energy decreases in the Nordic countries as a result of the temperature rise,

the change will sooner or later also have an influence on transmission pricing structures of

distribution companies. As a response to extreme weather phenomena (hot weather, severe

frost), it may be necessary to dimension the distribution network in a way that is

disadvantageous to power distribution, which may lead to an emphasis on standard tariffs in the

tariff structures.

3.5. Environmental issues

Considering environmental issues, the use of impregnated wood in network construction has

been a topic that has received most attention in recent years. In Finland, impregnated wood has

been commonly used in the construction of overhead lines (the proportion of wood poles of all

impregnated wood products is shown in Figure 3.9). The popularity of wood poles has been

explained primarily by their low cost compared with the concrete and steel poles common in

Central Europe. Another reason for the large-scale use of wood poles is their good insulation

capacity against atmospheric overvoltages. In Finland, a new act became effective in 2002

adding impregnated wood to the list of hazardous wastes. As a result, all treated wood, wood

poles included, is regarded as hazardous waste, the disposal of which has to be carried out in

compliance with the regulations concerning hazardous waste. The regulations focus on CCA

preservatives (Chrome Copper Arsenic), which exited the markets permanently in 2006. In

Finland, 70 % of the industrially treated wood still in use has been impregnated with water-

based salt preservatives (C and CCA), and about 29 % with creosote oil. For creosote the

situation remains unresolved, and the use of creosote will probably continue until further notice.

52

0

50 000

100 000

150 000

200 000

250 000

300 000

350 000

400 000

450 000

500 000

1960 1963 1966 1969 1972 1975 1978 1981 1984 1987 1990 1993 1996 1999 2002 2005

Pre

ssur

e im

preg

nate

d w

ood

[m3 ]

Sleepers

Poles

Sawn timber

Figure 3.9. Production of pressure impregnated wood in Finland in 1960–2007 (Kestopuu, 2009).

The environmental effects of transformer oil are emphasised in areas where the transformer

substations are located in groundwater areas. Although the probability of transformer failure

and escape of oil is very small in groundwater areas, the authorities have requested for

compilation of protective action plans. Alternatives and additional structures suggested for

traditional transformer structures are construction of an oil catchment tank, placing a control

blanket into the ground, replacing an oil-insulated transformer with a dry-type transformer, or

replacing conventional transformer oil with an environmentally friendly oil.

At present, magnetic and electric fields do not seem to constitute a significant problem in

electricity distribution networks. The maximum values for exposure to electric and magnetic

fields are 5 kV/m for and 100 µT, respectively. In distribution networks, the values for electric

and magnetic fields are typically < 2 kV/m and 3 µT. If these limit values are to be tightened, it

may prove difficult to meet the requirements in some cases in urban networks, where the

distribution substations are placed in the basements of residential buildings.

The use of sulphur hexafluoride (SF6) in electricity transmission and distribution has been under

threat for some time already. Although SF6 is an extremely ”strong” greenhouse gas, its use has

not been restricted so far, because the minor emissions in the field have been considered

insignificant from an environmental point of view. However, the operators are conscious of the

53

problem and have been taking various actions either to abandon SF6 and to find some other

alternatives such as vacuum switchgear.

In the future, landscape issues will gain importance. Solving questions related to land use will

be more and more time consuming, as the land owners have negative attitudes towards

construction of overhead lines and substations on their property. Underground cabling, instead,

is seen in more positive light. Hence, this creates incentives for wider-scale adoption of

underground cable alternatives in network construction.

3.6. Risk of blackouts

Climate change has raised the question of an increase in severe weather phenomena. Such

extreme weather phenomena may cause a large-scale blackout in the overhead line networks.

Recent years have witnessed some severe storms both in Finland and abroad. In 2005, the storm

Gudrun caused major damage to the electricity distribution infrastructure in Sweden; according

to the statistics, the storm damaged over 20 000 km of power lines. Although such massive

damages are less likely in Finland, the network operators have to be aware of the risk of

blackouts and prepare for large-scale supply interruptions both by network technology and at

the level of organisation. The large overhead networks in rural areas in particular are vulnerable

to blackouts. There have been attempts to reduce the risk of blackouts by preparing various

contingency plans. To this end, distribution network operators are required to devise a

contingency plan that is approved by the authority. A blackout is defined as an electrical power

failure, during which more than 20 % of the end-customers are left without electricity supply or

there is a sustained fault (several hours) in a primary substation or a main transformer. A

contingency plan shall include action plans for the distribution network, the personnel and the

organisation, which will be followed through on the occurrence of a blackout. The contingency

plan also includes a description of situations for which the operator prepares (risk analysis) and

objectives at which the plan is targeted. The objectives may differ between distribution

companies operating under different conditions; in large, densely populated urban areas and

cities, the target may be 100 % backup capacity, whereas in rural areas, the target may be set at

70 % (of the peak load). In rural areas, also longer target values can be accepted for restoration

times compared with those for large urban areas. On the occurrence of blackouts, the network

54

operator shall report the actions taken; on the basis of these reports, the Energy Market

Authority will be able to assess how the distribution company has met its obligation to develop

its operations.

The focus of the contingency plan has primarily been on providing the resources for fault repair

as efficiently and fast as possible. In the long run, the risk of blackouts can be reduced by

modifying the network structure and topology: by increasing the proportion of underground and

overhead cables in medium- and low-voltage networks and by replacing pole-mounted

distribution substations with kiosk substations. In the regulation, economic incentives for

preparing for blackouts are realised through the compensation system, according to which the

electricity users are entitled to financial compensations if they experience interruptions that

exceed 12 h (Electricity Market Act). The compensation that the distribution system operator

has to pay depends on the duration of the interruption and the annual system service fee of the

customer. The amounts of the standard compensations of the annual system service were

presented in section 3.3.

Considering the public image and reputation of the distribution companies, it is in the operators’

interest to reduce the risk of blackouts: large and long-lasting supply outages are bad publicity.

Figure 3.10 illustrates the effects of a severe weather phenomenon on the reliability of a

distribution network in a rural area in Finland. A major storm was experienced at the end of

November in 2008 in the operating area of the distribution company Järvi-Suomen Energia Oy.

The weather event lasted over 30 hours. At the worst, over 20 % of the end-customers were

affected by the electricity outage. Development of the faults and the number of end-customers

without electricity during the storm is illustrated in Figure 3.11.

55

Helsinki

Turku

Lappeenranta

LappeenrantaLappeenranta

100 km

Figure 3.10. Example of the effects of a severe weather event on the reliability of a distribution network.

The white line illustrates a network section that is left de-energised as a result of a fault. The total length

of the medium voltage network is over 8500 km.

Because of the unpredictability and complexity of blackout phenomena, taking the risk of

blackouts into account in the network strategy is a challenging task. Furthermore, forecasting

the climate change and susceptibility to blackouts in the future, for instance for 20 years ahead

is very challenging if not impossible. In general, the risk of blackouts can be reduced by

network technology (e.g. underground cabling) and by developing the fault contingency

organisation of the distribution company. In the strategy work, preparing for the risk of

blackouts calls for background information about the previous blackouts in the operating area

with the emphasis on the effects of blackouts and operation of the network organisation. Figure

3.11 presents the temporal effects of the blackout in a distribution company based on the major

storm depicted in Figure 3.10. The figure shows the number of customers left without electricity

supply in a blackout that lasted about two days. The mathematical and techno-economic

modelling of blackouts is discussed in more detail for instance in (Kaipia et al., 2007) and

(Brown, 2009).

56

77

19944

0

10

20

30

40

50

60

70

80

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

23.11.2008 24.11.2008

Num

ber

of fa

ults

in th

e ne

twor

k

0

5 000

10 000

15 000

20 000

25 000

End

-cus

tom

ers

with

out e

lect

ricity

Faults

New faults during therepair work

End-customers

Figure 3.11. Development of the number of customers left without electricity supply during a blackout

(Lohjala, 2009).

Figure 3.11 illustrates the curve form typical of blackouts: first, the numbers of faults and end-

customers without supply are fast increasing; then, after peaking, the number of end-customers

without supply reduces first rapidly in proportion to faults cleared, and after that at a

diminishing rate. In the example case, the first effects of the storm were shown on the

distribution network at noon on 23 November 2008. During the first six hours (12–18 hours),

the effects were at their largest; in this time period, almost 20 000 end-customers were left

without electricity. In the following six hours (18–24 hours), the influence of faults could be

limited to 8 000 customers by focusing on faults on the medium-voltage network; this result

was largely due to calming down of the storm and the efficient operation of the repair

organisation. About a day after the storm, only a few hundred customers remained without

supply. The small number of customers without supply is explained by the fact that the faults in

the medium-voltage network had been repaired already and the repair activities were focused on

low-voltage networks. Depending on the scope and strength of a storm, this ”tail” owing to the

repair operations in the low-voltage networks can become very long; for instance, in the storm

Unto, the last faults on the low-voltage network were repaired five days after the storm had

started. This tail (duration of repair work) can be cut by the choice of low-voltage network

components, such as underground cabling.

57

In Finland, standard compensations paid to end-customers between 2005 and 2008 amounted to

6.6 M€, as shown in Figure 3.12 (EMA, 2009b). During this period, the number of distribution

companies paying standard compensations has varied between 18 and 29. The average

compensation has been 44–64 €/customer,a depending on the year. When the standard

compensations paid to the customers are divided equally between the distribution companies

paying these compensations, the average compensation becomes 0.7–4.7 €/customer,a. The

compensations proportioned to the network length (MV + LV) have varied between 1.4 and

10.4 €/km,a. The highest standard compensations in proportion to the network length have been

102 €/km in a single distribution company in a year. The figure illustrates the numbers of end-

customers entitled to standard compensations in each year. The figure shows that although more

compensations were paid in 2006 than in the previous year, the number of customers entitled to

compensations was smaller.

0

500 000

1 000 000

1 500 000

2 000 000

2 500 000

3 000 000

2005 2006 2007 2008

Year

Sta

nd

ard

co

mp

en

satio

ns

[€/a

]

0

10 000

20 000

30 000

40 000

50 000

60 000

Nu

mb

er

of c

ust

om

ers

Over 120 hours

72-120 hours

24-72 hours

12-24 hours

Number of customers

Figure 3.12. Standard compensations paid to customers in Finland in 2005–2008.

In the last two years, the standard compensations have been considerably lower than in the first

two years; however, it is not possible to give a reason for this because of the relatively short

time period of standard compensations paid in Finland.

58

3.7. Scarcity of resources

An emerging challenge for distribution companies is the retiring personnel and disappearance of

tacit knowledge and know-how. The electricity distribution sector has for a long time been

characterised by a high average age of the workforce; the field has not managed to attract young

skilled people similarly as for instance the electronics industry. On the other hand, over the past

years, distribution companies have sought cost efficiency by cutting personnel expenses, which

has reduced the number of young workers, both electricians and planning staff. An analysis of

the personnel age structure and the ageing network infrastructure raises a justifiable concern

about how to meet the challenges related to the future extensive network renovations. Although

there are more and more external service providers available both in the construction and

planning industry, these alone cannot meet such a massive need for labour in the entire field in

the near future. There are already signs of the increased retirement of personnel both in Finland

(Adato, 2009) and abroad (Lave et al., 2007) and (Wijnia et al., 2006).

0

5

10

15

20

25

- 19 20-24 25-29 30-34 35-39 40-44 45-49 50-54 55-59 60-

Personnel age group

Per

cent

age

[%]

2001

2002

2003

2004

2005

2006

2007

Figure. 3.13. Age distribution of personnel in electricity distribution and district heating companies in

2001–2007 (Adato, 2009).

Key questions are which of these operations will be organised in-house and which will be

outsourced. Before answers can be found to these questions, it is necessary to define the

essential functions and operations on which the business of the company is based and which

constitute the company’s core competences. Obviously, work done by human labour will be

59

more expensive in the future. This encourages to adopt network automation and other solutions

that reduce the dependency on human resources.

3.8. Increase in material and labour costs

Large renovation investments taking place in the distribution network companies and the

simultaneous strong growth in Asia have an influence on the availability and price of materials

(cables, transformers) and labour. This forces to extend the timetable of investments, and on the

other hand, to find alternative structural solutions. The recent price development in the

construction industry can be illustrated by the building cost index as shown in Figure 3.14.

Total index

Labour

Other inputs

Materials

Rel

ativ

e va

lue

Total indexMaterial

Labour

Other i

nputs

Figure. 3.14. Development of building cost index in 2000–2009 (Statistics Finland, 2009).

The latest financial crisis may promote network renovations as resources are released from the

slowing building and dwelling production to the construction of basic infrastructure. The

current recession is also shown by decreased sales in the distribution network companies; this

trend, however, makes it possible to direct resources to network renovation targets. On the other

hand, closing down production units makes the implementation of large renovation projects

more difficult because of arising material acquisition problems.

The increase in labour costs is reflected both in the network construction technologies and in

the price differences between different technologies. In the field, labour costs will gain even

more significance in years to come. The phenomenon manifests itself in particular in the

juxtaposition of underground cables and overhead lines. Compared with underground cabling,

60

construction of traditional overhead lines requires more labour for maintenance and repair of

the line structures. The current increase in labour costs together with the downward-sloping

trend of underground cabling costs promote the penetration of underground cabling into

network renovation projects (Figure 3.15).

UNDERGROUND CABLING

OVERHEAD LINE CONSTRUCTION

TIME

INV

ES

TM

EN

T C

OS

TS

Finland Sweden

Figure 3.15. Development of overhead line and underground cable construction costs.

The above-described quality incentives from the regulation of electricity distribution network

business and the factors related to the risks of blackouts also speak for more extensive use of

underground cabling in distribution networks.

3.9. Energy policy

The national and international energy policies create various drivers also for the electricity

distribution business. Energy efficiency, distributed generation and reduction of dependency on

oil are key issues in the international energy policy. Some definitions of policy and targets set

by the EU are given below (European Council, 2007).

Energy must be sourced as diversely as possible

Energy must be sourced as diversely as possible. This promotes competition in the energy

market and improves reliability and ability to survive on the occasion of disturbances. Therefore

it is of high importance that no form of energy generation is excluded from the consideration.

61

Considering the development of electricity distribution networks, the above may result in an

increase in distributed generation and smaller generation units on the distribution networks. In

the future, the networks have to be designed so that the possible small hydro power plants can

be more easily connected to the electricity distribution system. This may pose a challenge

especially in rural areas, where the transmission capacity is usually limited because of small

loads on the network. As a result of these future changes, network protection issues will also

become more complicated.

Climate change will be mitigated with emissionless sources of energy

Climate change can best be mitigated by using emissionless sources of energy, such as nuclear

energy and renewable energy, and by improving energy efficiency. To this end, it is necessary

to provide for the conditions for production of emissionless sources of energy. The

competitiveness of renewable energy sources has to be promoted by research and development

activities. When promoting the use of bio-based energy in the industry, it has to be ensured that

the acquisition of raw material at a competitive price is not endangered.

Considering the development of electricity distribution networks, special attention has to be

paid to fields that provide potential application areas for instance for small-scale hydro power.

Increase in the cost of energy should be curbed

Cost of energy can also be influenced by efficient use of energy. A challenge will be to find

suitable incentives to encourage all energy users to improve the energy efficiency of their

operations. The energy efficiency of enterprises, which is already at a good level, is best

promoted by energy-efficiency contracts.

In electricity distribution network operations, energy efficiency aspects are reflected in the

selection of conductor cross-sections and transformer structures. At the power system level,

answers are sought from DC distribution, where the present transformer structures could be

replaced by power electronics components. This would reduce the dependency on transformer

62

construction materials, the prices of which are increasing, and cut losses in the low-voltage

network.

In March 2007, the Council of Europe defined energy efficiency as a key issue in the energy

and climate change strategy. The Council set a target to reduce energy consumption by 20 % by

2020. The EU Directive on energy end-use efficiency sets out an obligation to save 9 % of final

energy by 9 % by 2016 (European Council, 2007).

3.10. Distributed generation and smart grids

The impacts of distributed generation on electricity distribution business will be significant in

the future. In the past few years, substantial sums of money have been invested in research on

distributed generation. Potential forms of generation that will have an influence on distributed

generation are fuel cell technology, wind power, solar and bio-based energy and diesel power.

Fuel cell technology as a source of energy in every home would radically change electricity

distribution. For the time being, the technology is not an economically feasible solution yet.

Wind power is gaining ground especially in coastal areas and open mountain regions. In

distribution networks, wind power has chiefly cost-increasing effects. Solar power instead has

no direct impact on distribution networks. Bio-based energy may reduce the need for energy

transfer, while the need for power transmission will remain. The use of bio-based energy may

increase considerably in the years to come. Considering hydro power, the situation is more

established, as the capacity available has in practice been harnessed already. The use of diesel

power as backup power is increasing.

Although no significant breakthroughs have been made in distributed generation, the general

technology advancements may make distributed generation an essential element in distribution

systems. Electricity distribution network will then function as a genuine marketplace for energy

generation and use (Figure 3.16). Every electricity user will be able to participate in the markets

by reducing power consumption by an agreed amount at a defined moment, and obtain as

income a sum proportioned to the difference of the market price and the user’s contract price.

63

Figure 3.16. Principle of a smart grid (European Commission, 2006).

An increase in distributed generation has to be taken into account in network dimensioning, and

in particular, in protection arrangements and automation. For the time being, distributed

generation plays only a minor role in electricity distribution networks, and is therefore outside

the scope of this work.

3.10.1. Smart grids and electric cars

The character of transport and energy use is radically changing along with the upward trend of

electric cars. This creates a challenge to the existing electricity distribution infrastructure.

Depending on the electric car charging method, the peak load may increase considerably on the

distribution network. This means additional investments in larger cross-sections of underground

cables and overhead lines and more transformer capacity. Several analyses have been made to

investigate the network effects of additional charging power. Figure 3.17 illustrates a simulation

example of the effect of the vehicle charging load on the loading of a medium-voltage feeder in

four different charging alternatives (Lassila et al., 2009a).

64

0

1

2

3

4

5

6

7

8

9

10

0 2 4 6 8 10 12 14 16 18 20 22

0

1

23

4

5

6

78

9

10

0 2 4 6 8 10 12 14 16 18 20 22

0

1

2

3

45

6

7

8

9

10

0 2 4 6 8 10 12 14 16 18 20 220

1

2

3

4

5

6

7

8

9

10

0 2 4 6 8 10 12 14 16 18 20 22

Direct night-time charging Split-level night-time charging

Optimised charging

20 kV feeder

(densely populated area)

- Peak load of the day: 6.6 MW

- Minimum load of the day: 4.0 MW

- Number of electric cars: 2000

- Driving distance: 57 km/car,day

- Energy consumption: 0.2 kWh/km

- Charging energy: 11.5 kWh/car,day

� 22.9 MWh/day for all cars on the feeder

- Charging power: 3.6 kW/car

- Additional power on the feeder: 0–3.5 MW

(depending on charging method)

Charging energy (E) is equal in each charging alternative.

Pea

k p

ow

er [

MW

]

Working-hour and time-off charging

EE

Figure 3.17. Four vehicle charging models for a feeder in a densely populated area. In each figure, the

lower curves (black) represent the existing peak load, while the upper curves (blue) represent the load

when the charging power is taken into account (Lassila et al., 2009a).

The amount of investments required can be estimated by defining the average marginal cost of

the network. It is based on the network replacement value and the maximum load of the year,

and it describes how much the network capacity has cost for the distribution company per each

peak load kilowatt. In the example network of Figure 3.18, the network value compared with

the peak load is 320 €/kW in the low-voltage networks, 300 €/kW in the medium-voltage

networks and 100 €/kW at the primary substation level.

The additional network investments are paid by the end-customers. Because the replacement

value of the case network is 50 M€ (2.9 M€/a calculated by p = 5 % and t = 40 a) and the

annual delivered energy in the distribution company is 200 GWh, the network value per

delivered energy is 1.46 cent/kWh. The estimated additional annual charging energy required

by electric cars would be 46 GWh (11 000 cars, 20 900 km/car,a and 0.2 kWh/km,car).

Depending on the charging method and the voltage-level-specific analysis of the increase in

power, a rough estimation of the required investments in a new transformer and transmission

capacity in the whole distribution network would be 0–20 M€ (0–1060 k€/a), which equals 0–

1800 €/customer. The new distribution fee would be 1.18–1.66 cent/kWh after the network

reinforcement. This fee range shows that when the peak power of the network increases more

than the delivered energy, the distribution fee will increase. If the additional charging load has a

slight effect on the peak power, it is possible to cut the distribution fees.

65

3.11. Technology development

The above issues constitute the major challenges for the present electricity distribution business.

From the perspective of business, in addition to challenges, considerable advancements have

also taken place, for instance related to information systems and network technologies. The

most significant steps forward have been the AMKA aerial bundled cables introduced in the

1960s to replace bare low-voltage overhead lines, the remote operation systems taken into use

in the 1970s, network data management systems and remote-controlled disconnectors in the

1980s and the distribution management systems for distribution systems in the 1990s (Figure

3.18).

1950 1960 1970 1980 1990 2000 2010

Electrification of rural areas

Remote-controlled network systems

Remote-controlled disconnectorsNetwork information systems

Distribution management systemsFault location function

Organisational changesService providers Renovation of distribution networks in rural areas

Market liberalisationSupervision of distribution companies

Aerial bundled cables (AMKA)

Underground cabling in medium-voltage networks in rural areas

Figure 3.18. Development of electricity distribution business and significant advances in the field.

3.11.1. Network data systems and management of information

Electricity distribution companies in Finland are generally becoming more dependent on data

systems such as the GIS-based network data system, SCADA, and the distribution management

system. As a result of an expanding use of real-time metering points and advanced network

automation in distribution networks, the total amount of available real-time network status

information to be processed and analysed by distribution companies is growing. This

development trend on the one hand is setting the road for service providers specialised in

collection and analysis of network data, but on the other hand, new competence requirements

are set for the distribution companies. All in all, the network operation function is becoming a

strategically important knot within the management and sharing of network data.

Fully digitalised medium- and low-voltage networks require the use of special tools such as a

distribution management system. The role of reporting is becoming central especially towards

the energy authorities regarding the reimbursement proceeding and the end-customer service as

66

a part of fault management. In this sense, the distribution companies will be increasingly

dependent on network databases and their maximum use of capacity in the future (Brådd et al.,

2006).

3.11.2. Development of materials, working methods and automation

The increasing needs for improved reliability, lower operational costs (reduction in the need for

human resources) and better access to detailed network information create incentives for

development of materials, working methods and network automation.

Underground cabling

The high price of underground cabling limits the larger-scale use of cables in network

construction. The construction of a medium-voltage cable is particularly expensive. Nowadays,

underground cables are chiefly installed by applying excavation technology, and the cable itself

is notably more expensive than for instance a low-voltage cable. Therefore, preconditions for

wider utilisation of underground cabling are the development and application of lower-cost

cabling methods. Cost savings can be achieved by developing the cable structures, by using

low-voltage cables instead of medium-voltage cables (utilisation of 1 kV and LVDC

technology) and by developing the cable ploughing methods. Cost components related to

underground cabling are presented in Figure 3.19. The highest pressures are put to reduce costs

at the distribution substations and cabling structures.

For instance 95 mm2

25 €/m

Excavation:

10-15 €/m

Ploughing:

2-4 €/m

Depending on transformer density in the area, for instance

5 €/m

Depending on technology (centralisedor distributed), for instance

1-3 €/m

For instance 500 kVA50 k€/unitCase area 500 km:���� 0.1 €/m

CABLE CABLING RENOVATION OF DISTRIBUTION TRANSFORMER

COMPENSATION OF EARTH FAULT CURRENTS

BACKUP POWER

Figure 3.19. Cost components in underground cabling.

67

Ploughing and excavation of underground cables

Cable ploughing as a low-voltage cable installation method is becoming increasingly common

especially in rural areas. Nowadays, when the circumstances allow it, nearly all low-voltage

underground cables are installed by ploughing. This way, the installation costs can be kept

reasonable; consequently, low-voltage cabling is a more inexpensive solution than the

conventional AMKA aerial bundled cable structures. In rural areas, the overall cable ploughing

costs are in average 50 % lower than the excavation costs of a cable trench alone. The soil

somewhat restricts the potential targets for cable ploughing; nevertheless, ploughing is possible

everywhere except in a very stony or rocky soil. A survey in the area of the distribution

company Järvi-Suomen Energia Oy showed that ploughing is an applicable method in 80 % of

the total low-voltage network. Usually, preferable areas for cable ploughing can be found by the

roadsides and road beds. The ploughing speed depends on the scope of the target; however, it

can be several kilometres a day.

3.12. Summary and conclusions

The strong dependency on the operating environment creates various obligations for the coming

years. In particular, the ageing networks together with the regulation of electricity distribution

business bring challenges to the long-term development of distribution networks. Rather than

challenges, the large-scale renovation needs and the general technological advancement can

also be seen as an opportunity. By adopting new structural solutions in a cost-efficient way, the

renovation can be carried out so that the obligations defined by the authority will be met, and

the asset management in the distribution company develops in a favourable direction. There are

various issues that require the renovation of the network; and most obviously, with other than

the present technology. Table 3.4 presents the most central environmental factors affecting the

distribution network business.

68

Table 3.4. Summary of the effects of operating environment on the distribution network business.

Phenomenon Consequence Remarks

Ageing of networks Renovation needs Opportunity

Regulation Outage costs

Outage cost (KAH) values

Profit

Standard compensations

Reliability criteria

Efficiency measurement (benchmarking)

Lifetimes

Short and long supply interruptions

Minimisation of total costs

Owner policy

Penalty

Development obligation

OPEX limit

Risks

Owner policy Profit target

Pricing target

Reliability target (media)

Investment resources

Quality of electricity Outages through regulation

Voltage dips

Voltage

Backup supplies

Climate change Blackouts

Changes in loading

Weather-proof network

Environment Wood poles, restrictions Competitiveness of overhead lines suffers

Labour costs Construction of overhead lines becomes

more expensive

Underground cabling costs are reduced

Mutual position of overhead lines and

underground cables changes

Distributed generation Bidirectional power transfer Challenge of manageability

Smart grids Active loads and generation Reduction in energy transfer

Cost pressures

Electric cars New load on the network

Energy storage

Energy efficiency

Technology advancement

(1 kV, DC)

Transmission capacity of the low-voltage

network

Mutual position of medium- and low-

voltage networks changes

Decreased load growth Less electrotechnical development needs Age and reliability requirements

emphasised

69

4. Methodology and tools of strategic analysis

Electricity distribution network business is characterised by management and analysis of large

amounts of data. In the development of business activities, statistics covering a long time span

are utilised for instance when analysing the development of costs and reliability of electricity

supply. In (Grünig and Kühn, 2006, p. 53) “the main emphasis is on data collection in three

fields; global environment, specific task environments or industries and the company itself.” ---

“In practice, it is often difficult to determine the scope of strategic analysis; at this stage in

strategy development we do not yet have a clear view about the target market positions and

competitive advantages. Therefore we do not know what information we will need. For this

reason there is the danger that a large amount of data will be gathered which will later turn out

to be irrelevant to decisions being taken. This must be avoided, because strategic analysis is a

particularly expensive undertaking.”

Figure 4.1 illustrates the diversity of the operating environment and network company

operations especially from the viewpoint of asset management and information flows. A

successful network strategy calls for commitment of all parties to the collection of data. Single

information sources and stakeholders in the process constitute a foundation for the practical

strategy work. The figure does not depict all the actors and information sources required in the

development, but serves as an example only.

70

NISNIS

LTPLTP

Trends and guidelines for the long-term network development and information management

Asset management

Network operation

• Load development and historic data• Outage statistics• Network switching times (fault

isolating) and alternatives

• Interest rates• Valuation of losses• Component lifetimes and age

distribution• Outage cost parameters• Pricing of components and work,

cost development

Network construction

Maintenance and fault repair

Network planning

• Present state of the network (loads, power losses, voltage drops, backup supply considerations)

• Maintenance and fault repair costs• Fault repair times• Empirical data on components

• Actual cost of network construction• Actual application potential of different network

technologies• Soil properties (cabling)

Research and consulting• New network technologies• Analysis models and tools• Utilisation of the experiences of

other actors in the field

LONG-TERM PLANNINGTarget group and information flows

Society• Land use planning, growth forecasts• Land use options• Finnish Meteorological Institute: climate, weather• Environmental office and ground water areas

Figure 4.1. Targets, information flows and stakeholders in the operating environment of a distribution

company.

“Correctly understood and unbureaucratically applied strategies will generally increase the

quality of daily operational decision-making. Strategies used as management tools can help to

prevent companies from slipping into competitive positions and markets which offer little hope

of success” (Grünig and Kühn, 2006, p. 17).

As the network operations are increasingly turning towards service production, it is necessary to

guarantee uninterrupted information flows between the distribution company and service

providers (Lassila et al., 2009c). The situation may prove very challenging especially if the

network planning and operative functions (network management) are to be unbundled. Now

there is a risk that the targets and actions defined by the company owners for the network

development are not conceived in the same way at all levels of network planning and operation.

71

The survey of the operating environment presented in Chapter 3 may reveal new issues that

oblige the company to draw up or update a development strategy and to radically renovate the

distribution network. The needs of society, technical solutions and development methods have

evolved in the course of time to such an extent that it is no longer either economically or

technically feasible to carry out renovation according to the traditional principles. Because of

the long lifetimes of network investments, the operating environment data have to be taken into

account as extensively as possible in strategic decision-making. The structural choices made

today will at best or worst be visible in the distribution systems for half a century. So far, major

changes in the policy have been avoided either consciously or unconsciously, or changes have

been postponed by concentrating for instance on replacing wood poles instead of making more

radical changes in the network structure or topology. Taking into account the essential needs for

changes (Chapter 3) in network development requires an in-depth analysis of the following

issues.

- Which are the most compelling factors driving network renovation (network age,

reliability, ownership issues, pressure from society)?

- What network development alternatives are there; what is their techno-economic potential

in the company’s area of operation?

- What are the long-term cost and reliability effects of different development methods?

- What background information, calculation parameters and methods are used in the

strategy process?

- What are the owners’ objectives, and what are the opportunities and tools provided by the

owner(s) for network development (return expectations, investment in network

development)?

Finding answers to the above questions calls for an adequate and covering analysis of the

operating environment but also development of various analysis tools and calculation

methodology as well as interactive discussion with the network owners. The process is

challenging and time consuming, but necessary in order to find cost-efficient solutions.

This analysis related to the above questions can be referred to as ‘strategic analysis’ or ‘strategy

process’.

72

4.1. Drivers of the strategy process

In the network strategy work, the focus is on defining the most critical needs that require and

direct network renovation. The reasons for large-scale renovation can be found among the

environmental factors described in Chapter 3, such as the age of the network, poor reliability,

changes in the owners’ objectives, development of the needs of society or changes in

legislation. Figure 4.2 sums up the most essential reasons, or drivers, for network renovation.

The dashed line illustrates the cross effects of authority operation.

Reliability of networks

Network renovation

needs

- Increase in fault rates- Threat of climate change- Risk of blackouts- Public image of the company

Owner

- Return expectations (asset management)- Public image of the company- Reliability and quality of electricity- Susceptibility to blackouts (standard

compensations)- Environmental regulations (e.g.

preservatives) - Maintenance of human resources, skills

and knowledge- Development in the operating area (loads)Load development

- Insufficient distribution and transformation capacity

- Tighter requirements set by owners and authorities e.g. from the aspect of backup power situations

- Development needs in declining areas

Authority

- Obligation to develop the network (Electricity Market Act)

- Threat of reduced return- Tightening distribution reliability criteria

and entry of outage costs - Public image of the company (e.g.

efficiency benchmarking)- Susceptibility to blackouts

(standard compensations)- Environmental regulations (e.g.

preservatives) - Increase in the weight of operational costs

(has an effect on selection of network structures, e.g. automation issues)

- Electrical and occupational safety requirements

New technologies

- Renovation can be carried out cost efficiently

- Investment, operating and outage costs can be affected

- Amount of automation can be increased (has an effect especially on operating and outage costs)

- Risk of blackouts can be reduced byunderground cabling

Network age and condition

- Distribution network reaching its lifetime- Has a strong impact on allowed return - Electrical and occupational safety aspects

Resources

- Increasing shortage of labour?- National and global shortage of materials

and increase in prices- Simultaneous renovation needs

everywhere

Figure 4.2. Drivers for network renovation.

There is seldom only a single reason for network renovation. For instance, in network areas

suffering from poor reliability, the high network age and poor mechanical condition may be

reasons for renovation. In large-scale network renovation, some compromises may also be

necessary. Although the age or reliability of the network do not necessarily require any actions,

shortage of distribution capacity may force to renovation. This may lead to renovation of such

network sections, the age of which does not call for renewal yet. Such situations have to be

evaluated case by case, as replacing network components in the middle of their lifetime reduces

the efficiency of operations and increases costs.

73

4.2. Network technologies and potential surveys

As described above, the reasons for large-scale distribution network renovation can be diverse.

Once the need for renovation has been recognised, different renovation methods suitable for the

areas of operation are determined. Depending on the initial situation, the targets for the

renovation may be to improve the age structure of the network to ensure better return, or to

make the distribution network completely immune to adverse weather phenomena. For the

evaluation of the feasibility and strategic value of different network technologies, it is essential

to know how much economic potential there is for the technology in question in the operating

environment. Even a network technology and development solution that could be economically

adopted to the system may be strategically irrelevant if the number of economically feasible

targets is marginal in the distribution network.

The possible boundary conditions set for the network for instance with respect to reliability may

rule out some development technologies. Similarly, boundary conditions set by the operating

environment, such as a high forest rate or restricted amount of land suitable for underground

cabling may limit the number of technical structural solutions available. In the following, some

development technologies that are feasible in the Nordic distribution operating environments

are introduced and discussed. For each technology introduced, it is described how the techno-

economic feasibility of the technology can be analysed. Typical network technologies available

are transfer of overhead lines to roadsides and replacement of lines with covered conductors

(plastic-covered conductors), overhead and underground cabling, circuit reclosers, primary

substations, suppression of earth fault currents and the 1000 V low-voltage technology.

4.2.1. 1000 V low-voltage technology

An example of a novel electricity distribution technology and a techno-economic potential

survey is the 1000 V low-voltage technology. Since 80–90 % of the outages experienced by

end-users result from faults in the 20 kV medium-voltage network, the reliability of electricity

distribution can be considerably improved by reducing the size of supply sections and thereby

the areas of influence of faults. The technology is particularly applicable to rural areas, where

medium-voltage networks typically include a lot of branches; in these areas, the powers are

74

relatively low and reliability poses challenges to the system (Kaipia, 2004), (Lohjala et al.,

2004), (Lohjala, 2005) and (Lohjala et al., 2005). In such places, the 1000 V system can be used

to economically replace medium-voltage branch lines of a few kilometres. As the 1000 V

system constitutes a protection zone of its own, the length of the medium-voltage network will

decrease and the reliability of electricity distribution in the area will improve. The potential

surveys made for Nordic distribution companies have shown that up to 40 % of the total length

of the medium-voltage networks could be replaced with the 1000 V low-voltage technology

when the system is renovated for the next time. Considering the financial value of the medium-

voltage networks in the distribution network business as a whole, we may state that the 1000 V

technology has significant economic potential.

Targets on a MV feeder

Economically feasible area

Figure 4.3. Feasibility study of the 1000 V technology. In the area between the curves, the lifetime costs of

the 1000 V technology are lower than the costs of the conventional technology. The dots indicate real

network line sections (Lohjala et al., 2005).

The feasibility curves plotted in Figure 4.3 are based on principles given in (Lohjala, 2005). The

upper limit of the techno-economic range of use is defined by the maximum allowed voltage

drop in the system. The lower limit is defined by the differences in investment, operation,

maintenance and outage costs between the 1000 V technology and the conventional network

construction method. The economic feasibility of the 1000 V technology relies strongly on

outage cost benefit, which in turn depends on the target area; that is, whether the technology is

used for feeders in urban or rural areas. All in all, there are significant incentives to apply the

1000 V technology in the Nordic operating environment. When appropriately applied to the

75

network strategy, the 1000 V would improve the cost efficiency of investments and quality of

supply experienced by the end-customers. The cost efficiency benefit of an investment is

manifested in particular when overhead lines are replaced with underground cables, and

alternative solutions are sought for costly medium-voltage underground cables.

4.2.2. Circuit recloser

A circuit recloser improves the reliability of network by increasing the number of protective

zones in the network. From the end-user’s perspective, the number and duration of faults

decrease as the faults occurring before the recloser are not shown to the customers at the

substation end of the feeder. The benefit reached depends on the network length downstream

from the circuit recloser (number of faults) and the number, type and energy consumption of the

customers before the recloser. The benefit reached with the recloser can be analysed with the

example of Figure 4.4, where the power of a single medium-voltage feeder is P and the total

length of lines is l.

P

l

Figure 4.4. Schematic of a circuit recloser on a medium-voltage feeder.

Now the outage cost is proportional to the power and line length P*l. It is assumed that the

loads and faults are evenly distributed on the feeder. The recloser is placed on the feeder so that

the power and line length both up- and downstream from the feeder are equal. The outage cost

of the feeder is proportional to the sum

PllPl

P ⋅=⋅+⋅ 43

222 (4.1)

Thus, the outage costs are reduced by 25 % compared with the initial state. In an actual

distribution network, typical questions are: a) on what conditions is a circuit recloser

economically feasible, b) in the case of a single circuit recloser, where is the best location of the

circuit recloser and c) in the case of several circuit reclosers, which are the best locations for the

76

recloser. In the optimisation task, a further challenge is provided by the fact that the loads and

faults are not evenly distributed on the feeder.

The techno-economic feasibility of a circuit recloser can be determined based on the acquisition

cost, fault rate and power demand of the customers in the target area. Equation (4.2) determines

what is the magnitude of power demand in the network section protected by the circuit closer

required for the circuit recloser to be economically feasible. The equation takes into account the

outage cost benefit for the customers before the circuit recloser in proportion to the annuity of

the recloser investment.

[ ])(

)1(1)(

dfault,operationnfault,faultDARDARHSARHSAR

INV

ctcncncnx

Cp

p

xPt

⋅+⋅+⋅+⋅⋅

⋅+−

=−

(4.2)

P = power demand

p = interest rate

t = reference period

CINV = investment cost of the circuit recloser

x = length of the network after the circuit recloser

nHSAR = number of high-speed reclosings (HSAR = high-speed autoreclosing)

cHSAR = unit outage cost of a high-speed reclosing

nDAR = number of delayed autoreclosings (DAR = delayed autoreclosing)

cDAR = unit outage cost of a delayed autoreclosing

nfault = number of long supply interruptions

cfault,n = unit outage cost of long supply interruptions (number)

tOperation = disconnection time of a faulted section

cfault,d = unit outage cost of long supply interruptions (duration)

Equation (4.2) can be illustrated by the example curve of Figure 4.5, where the feasibility limit

of the circuit recloser is given as a function of network length after the recloser and the power at

the substation end of the feeder.

77

0

200

400

600

800

1 000

1 200

0 5 10 15 20 25 30 35 40

Mea

n lo

ad o

f the

feed

er b

etw

een

supp

lyin

g en

d of

the

feed

er a

nd th

e ci

rcui

t rec

lose

r [k

W]

Techno-economic feasibility curve for a circuit recloser-

+

Network length downstream from the circuit recloser [km]

Figure 4.5. Techno-economic feasibility curve for a circuit recloser.

Cost calculation related to the position of the circuit recloser can be illustrated with the

following example. Here, the target of analysis is a medium-voltage overhead line feeder that is

experiencing reliability problems owing to the structure and location of the line. The reliability

of the network can be improved and outage costs can be reduced by limiting the most

vulnerable network section to constitute a protection zone of its own. In our example case, there

are four alternative positions for the recloser, shown in Figure 4.6. The target is that faults

occurring in the network section downstream from the circuit recloser will not be seen by the

customers in the network section before the circuit recloser.

3) ?

2) ?

1) ?

Feeder 1

Feeder 2

4) ?

Sustained faults: 5 pcs/100km,aHigh-speed ARs: 51 pcs/100km,aDelayed ARs: 11 pcs/100km,aReconnection time: 10 minutes

110/20 kV

1422 kW24 km4

1330 kW29 km3

1062 kW34 km2

455 kW36 km1

Mean load of the feeder between supplying end of the feeder and the circuit recloser

Network length downstream from the circuit recloser

1422 kW24 km4

1330 kW29 km3

1062 kW34 km2

455 kW36 km1

Mean load of the feeder between supplying end of the feeder and the circuit recloser

Network length downstream from the circuit recloser

Figure 4.6. Alternative positions for the circuit recloser on a 20 kV feeder 1. The total length of the feeder

is 44 km and the peak power is 4.1 MW.

78

Thus, the feasibility analysis of a circuit recloser is based on optimisation between the

investment cost and the outage cost benefit given by Eq. (4.2). In the calculation of outage cost

an average power is applied, as the moment of occurrence of a fault cannot be exactly

determined. The outage cost benefit depends on the customer distribution in the area. Table 4.1

presents the customer distribution and the weighted outage costs of the feeder.

Table 4.1. Customer distribution and weighted outage costs for the feeder in the example for a circuit recloser (HSAR = high-speed autoreclosing, DAR = delayed autoreclosing).

HS-AR DE-AR Customer

Weighted outage cost parameters

€/kW €/kWh €/kW €/kW sharesResidential 0.36 4.29 0.11 0.48 65 % 0.23 2.79 0.07 0.31Agriculture 0.45 9.38 0.2 0.62 2 % 0.01 0.19 0.00 0.01Industry 3.52 24.45 2.19 2.87 14 % 0.49 3.42 0.31 0.40Public 1.89 15.08 1.49 2.34 3 % 0.06 0.45 0.04 0.07Service 2.65 29.89 1.31 2.44 16 % 0.42 4.78 0.21 0.39

100 % 1.22 11.63 0.64 1.19

Sustained fault HS-AR DE-AR€/kW €/kWh €/kW €/kWSustained faultHSAR DAR HSAR DAR

In this simplified example, it is assumed that the customer distribution (in percent) is equal at

any part of the feeder. In reality, customer distribution may vary considerably between network

sections and the supply area of the distribution transformer. However, it is fairly safe to use the

average customer distribution as a basis in the calculations without obtaining too optimistic

results. This is explained by the fact that considering the outage costs, the most challenging

customers (services, industry and public loads) are typically located closer to the primary

substation, in other words, upstream from the circuit recloser. This is illustrated by Figure 4.7,

which shows the calculated outage costs experienced by the supply area of distribution

transformers of a distribution company during a fault interruption of one hour in relation to the

distance between the distribution transformer and the primary substation. The figure shows that

the largest outage costs occur chiefly in the supply area of distribution transformers close to the

primary substation. Therefore, in reality, the benefit of a circuit recloser is higher than what

would be expected from the calculations based on average customer distribution.

79

0 €

500 €

1 000 €

1 500 €

2 000 €

2 500 €

3 000 €

0 5 10 15 20 25 30

M uunt amon etäisyys sähköasemasta [ km]

Yh

de

m t

un

nin

vik

ak

es

ke

yty

ks

en

k

es

ke

yty

sk

us

tan

nu

s [

€/k

pl]

Distance between the transforming district and the primary substation [km]

Out

age

cost

s ex

perie

nced

by

tran

sfor

min

g di

stric

ts d

urin

g a

faul

t int

erru

ptio

n of

one

hou

r [€

/faul

t]

Figure 4.7. Outage costs experienced by the supply area of distribution transformers of an electricity

distribution company during a fault interruption of one hour in relation to the distance between the

distribution transformer and the primary substation. The outages are limited to 3000 €/pcs to enhance the

readability of the graph.

To explicate the techno-economic feasibility of the circuit recloser, by applying Eq. (4.2), it is

possible to plot a feasibility curve as shown in Figure 4.8. The figure shows that all the four

example locations of the circuit recloser are on the positive side of the feasibility curve. Curves

have been plotted for two different circuit recloser investment costs, 14 k€ and 28 k€. In

practice, the investment cost depends on such issues as how familiar the distribution company is

with the technology and how much has to be invested in information communications

technology in commissioning of the circuit recloser. In the unit price list of network

components for 2009, the price of a circuit recloser was 22,140 € (EMA, 2009a).

80

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 5 10 15 20 25 30 35 40

Network length downstream from the circuit recloser [km]

Mea

n lo

ad o

f th

e fe

eder

bet

wee

n su

pply

ing

end

of th

e fe

eder

and

the

circ

uit r

eclo

ser

[kW

] 3)+ 23 639 €/a

2)+ 22 130 €/a

1)+ 10 039 €/a

4)+ 20 917 €/a

Investment price: 28 000 €

Investment price: 14 000 €

Figure 4.8. Techno-economic feasibility studies on the selection of a circuit recloser and the calculated

annual savings in outage costs for four alternative locations (investment cost 28 000 €, p = 5 % and

reference period t = 30 a � annuity 1821 €/a).

In the example, the locations of the circuit reclosers are alternatives to each other. The techno-

economic benefit of the use of several circuit reclosers in series cannot be calculated by simply

summing up the benefits of single circuit reclosers. In the feasibility studies, there is a strong

interdependence between the circuit reclosers, similarly as between other investments affecting

reliability. This poses a challenge to the considerations of the development of optimal network

solutions. If the target is to place several circuit reclosers in series on the feeder, it is necessary

to take into account the presence of each circuit recloser when calculating the outage cost

benefit. In promoting a network strategy, advantages of a circuit recloser are its fast

implementation, cost efficiency and adaptability. If the calculations required to define the

optimal position of the circuit recloser and the set values of the control relay have already been

made and the required communications connections are available (e.g. if the circuit recloser is

placed at an existing disconnector substation), the circuit recloser can be installed in a quite

short time. The effects on the quality of supply are immediate and can be seen by a large

number of customers. Adaptability, that is, an opportunity to move the circuit recloser to a new

location, is an advantage especially when a long-term target in the strategy is to change over to

underground cabling, and there is a need to change the position of the circuit recloser at the

interface of the underground cable and overhead line networks.

81

4.2.3. Underground cabling, transfer of lines to roadsides, covered conductors

Pressures put on reliability and, on the other hand, the development of technical structural

solutions have led to a situation where attitudes towards renovation of overhead line structures

are becoming more critical. Underground cabling, transfer of lines to roadsides, or application

of covered conductors serve as alternatives to overhead line renovation. The techno-economic

feasibility of these solutions can be assessed by comparing the long-term investment, operation,

maintenance and outage costs between the solutions. The effects of renovation on the network

reliability are illustrated by the cabling example of Figure 4.9. In the example, the total length

of the network is l and the load P. The loads are evenly distributed along the feeder. Cabling is

carried out for the first half of the feeder.

P

l

fcable= 1 fault/100km,a foverhead line= 10 fault/100km,a

Figure 4.9. Schematic of a medium-voltage feeder with overhead and underground sections.

The outage cost is proportional to the power and line length P*l. With underground cabling, the

fault frequency of the underground section of the feeder reduces and the outage costs will

change compared with the initial situation as follows:

line overheadcableline overhead 22f

lPf

lPflP ⋅⋅+⋅⋅→⋅⋅ (4.3)

If the fault frequency of the cable is selected to be one tenth of the fault frequency in the

overhead line (Figure 4.9), the outage costs will reduce to 55 % of the initial costs (= 55/100).

Equation (4.4) provides a feasibility comparison between medium-voltage overhead and

underground cable networks. The equation is applied to determine the power of the feeder at

which the renovation alternative, the investment costs of which are higher, pays itself back as a

result of improved reliability and lower outage costs, also taking into account the differences in

repair and maintenance costs.

82

( ) numberPl,Pldurationfault,clearancenumberfault,faultDARDARHSARHSAR

repairemaintenancBINV,AINV,

fault

)()1(1

)(cnctcncncn

CCCCp

p

nP

t

⋅∆+⋅+⋅∆+⋅∆+⋅∆

∆+∆+−⋅+−

=∆

− (4.4)

P = power demand

p = interest rate

t = reference period

CINV,A = investment cost of the renovation alternative A (e.g. underground cabling)

CINV,B = investment cost of the renovation alternative B (e.g. overhead line)

∆Cmaintenance = change in the maintenance costs between the renovation alternatives [€/km,a]

∆Crepair = change in the unit prices of repair costs between the renovation alternatives [€/km,a]

∆nHSAR = change in the number of high-speed reclosings

cHSAR = unit outage cost of a high-speed reclosing

∆nDAR = change in the delayed automatic reclosings

cDAR = unit outage cost of a delayed automatic reclosing

∆nfault = change in the number of long supply interruptions

tclearance = clearance time (long supply interruption)

cfault,number = unit outage cost of long supply interruptions (number)

cfault,duration = unit outage cost of long supply interruptions (duration)

∆nPl = change in the number of work outages

cPl,number = unit outage cost of work outages (amount)

Figure 4.10 illustrates example curves for the applicability of underground cabling in the target

area. It is assumed that the overhead line structure has reached the end of its lifetime, and thus,

it is assumed to have no service value after the cable renovation. In Figure 4.10, the x-axis

shows the decrease in fault frequency when changing from overhead lines over to underground

cables (pcs/100km,a). The y-axis shows the peak power of the feeder in question.

83

0

200

400

600

800

1 000

1 200

1 400

1 600

1 800

2 000

2 4 6 8 10 12 14 16 18 20

Joht

oläh

dön

huip

pute

ho [k

W]

Roadside (from 5 � 1 faults/100km,a)Based on long-term statistics:

Fault rate UG cable OH forest OH roadside - Sustained faults 1 10 5 faults/100km,a

- HSAR - 25 14 pcs/100km,a

- DAR - 10 5 pcs/100km,a

- Maintenance 58 153 124 €/km,a

- Fault repair 44 100 60 €/km,a

HSAR = High-speed autoreclosing (~ 0.3–0.5 s)DAR = Delayed autoreclosing (~ 1–2 minutes)OH = Over head lineUG = Underground cable

z

z

110/20 kVFeeder 1

Feeder 2

a) Line in forest

b) Line next to road

Forest (from 10 � 1 faults/100km,a)

9

Analysis includes:

- Investment costs

- Operational costs

- Outage costs

P [kW]

Change in number of sustained faults [faults/100km,a]

Figure 4.10. Techno-economic ranges of use for 20 kV medium-voltage underground cables when the

existing OH line is in forest and next to a road.

It is assumed that when the existing roadside overhead line is changed over to an underground

cable, the rate of long supply interruptions will decrease from 5 to 1 faults/100km,a (= change is

4 faults). It can be seen from the figure that if the peak power of the feeder is more than 1700

kW, the renovation is profitable. When a forest-located overhead line is replaced by

underground cabling, the rate of long supply interruptions will decrease from 10 to 1

faults/100km,a (= change 9 faults). Now, if the peak power of the feeder is more than 700 kW,

the renovation is profitable.

Figure 4.11 illustrates example curves for the applicability of underground cabling taking into

account several cost factors. The approach provides the first insight into the assessment of the

practical techno-economic potential of the network technology in question. The different

feasibility curves in the figure are based on the different costs taken into account in the

underground cabling.

84

0

200

400

600

800

1 000

1 200

1 400

1 600

1 800

2 000

0 2 4 6 8 10 12 14

Change in long supply interruptions [faults/100km,a]

Pea

k po

wer

of t

he fe

eder

[kW

]

1) Cable + cabling = 30 k€/km

2) Cable + cabling + distribution substation renovation = 35 k€/km

3) Cable + cabling + distribution substation renovation + compensation = 37 k€/km

1) 2) 3) Interest rate p = 5 %, load growth r = 1 %/a and time period t = 40 a

For overhead line:- Unit price: 22 k€/km - High-speed autoreclosings 25 pcs/100km,a - Delayed autoreclosings 10 pcs/100km,a

Figure 4.11. Examples of the techno-economic ranges of use for 20 kV MV underground cables.

In the strategy-level planning, uncertainty related to statistics and fault frequency can be

managed by drawing up guidelines so that in the feasibility analysis of different structural

solutions, the parameters that are the most difficult to determine are left as variables in the

initial stage of the planning process. For instance, in the profitability comparison between

underground cables and overhead lines, when plotting the curves, the designer does not have to

consider and decide on the absolute fault frequency but rather on the amount by which the

target-specific fault frequency can change as a result of cabling.

The effects of underground cabling on reliability can be intensified by combined network

automation solutions. Now, after the cable section at the beginning of the feeder, a circuit

recloser is placed on the feeder to prevent the faults at the far end of the feeder from showing to

the customers at the substation end (beginning) of the feeder.

4.2.4. Compensation of earth fault currents

In a neutral-isolated medium-voltage network, the single-phase short circuit and earth fault

currents usually remain low. A typical overhead line structure produces, at a 20 kV supply

voltage, 4–5 A per hundred kilometres. In an underground cable network, the amount of

capacitive current is 1.5–3 A/km depending on the cable type. As a result of poor earthing

85

conditions, a situation may occur, in which, considering electrical safety, the earth fault taking

place in the medium-voltage network cannot be suppressed fast enough. Earth fault currents

increase considerably in areas where the medium-voltage network is renovated by replacing

overhead lines with underground cables. To compensate the increasing fault currents, earth fault

arc suppression coils have to be connected to the network.

Another significant benefit of earth fault compensation is the automatic suppression of the arc

occurring during an earth fault. This way, it is possible to avoid most of the earth-fault-related

reclosings required by non-suppressed networks. By investing in earth fault compensation, the

number of interruptions caused by high-speed auto-reclosings can be reduced by 50 %.

Suppression of earth fault currents is common in the Nordic countries. In Finland, 46 % of the

medium-voltage networks are provided with arc suppression (Finnish Energy Industries, ET,

2009). According to the statistics, there are on average 21 interruptions per 100 km caused by

high-speed auto-reclosings. In the network with a 50 km long feeder, the number of high-speed

auto-reclosings (HSAR) is

ar,HSAR/feede11km 100

HSAR21km 05 =⋅

(4.5)

The outage cost is proportional to the power and line length P*l. With suppression, the number

of reclosings decreases and the outage costs change from the initial situation as follows:

dcompensate line, overheaddcompensate-non line, overhead flPflP ⋅⋅→⋅⋅ (4.6)

If the reclosings are assumed to be halved by suppression, also the outage costs caused by

reclosings will be cut to half. If the average power of the medium-voltage line in question is 500

kW and the outage cost of a high-speed reclosing is 0.55 €/kW, the outage costs caused by

high-speed auto-reclosings are for one feeder:

afeeder,/€3025 0.55kW50011 kW€

aHSAR

feeder-HSAR =⋅⋅=C (4.7)

86

At a typical primary substation in a rural area, there can be for instance ten feeders, and the

annual outage cost saving for the entire network of this primary substation would be

a€k

feeder€

HSAR 3.30 302510 =⋅=C (4.8)

According to nationwide statistics, even 50–80 % of short interruptions can be reduced by earth

fault current compensation. The cost of the earth fault compensation equipment varies typically

between 1,000–3,000 €/A depending on the compensation method (centralised or distributed

compensation) and unit size. In the case of an overhead network, earth fault compensation for

the whole network of the primary substation would require capacity according to empirically

derived Eq. (4.9) (Pöyhönen, 1978).

A33A10300

50020

10300km

3A

V3=

⋅

⋅=

⋅

⋅

=

lU

I

(4.9)

The cost of compensation would be 33–99 k€ for the example network. If it is assumed that the

high-speed autoreclosings could be reduced by 50 % (= 15.13 k€/a) by this investment, the

repayment period (the interest rate p is 5 %), of this investment would be 2.4–8.1 years. In other

words, an investment pays itself back in eight years (Lassila et al., 2005a).

4.2.5. LVDC

Among the network technologies available, the low-voltage DC distribution (LVDC) represents

the newest technology (Kaipia et al., 2006) and (Salonen, 2006). With the LVDC technology it

is possible to transmit significantly larger powers than with the present 400 V low-voltage AC

system, or to use conductors with smaller cross-sections than the present ones. Although the

LVDC technology is still at a very early stage, and there is uncertainty involved in the prices of

power electronic components, it is possible to determine feasibility ranges at a principle level

for this technology also. Figure 4.12 presents a simplified example of an imaginary supply area

87

of the distribution transformer structure used in the cost comparison; in the comparison, the

structure is implemented with the present 20/0.4 kV technology and the LVDC technology.

20/0.4 kV (Pmax = 34 kW)20 kV

1 km

200 m0.4 kV

0.4 kV 0.4 kV

20/1 kV

± 750V

800 mAC/DC

± 750V

200 m

± 750V

200 m

DC/AC400 VAC

200 m0.4 kV

Pmax = 10 kW/cust

Figure 4.12. Example supply area of the distribution transformer implemented with the present and LVDC

technology.

Figure 4.13 gives feasibility curves for the LVDC technology and traditional technologies (20

kV overhead line, covered conductor (CC) and underground cable). Based on a case network,

the figure shows that the total costs of the LVDC solution (investments, OPEX and outage

costs) are the same as the total costs of an 20 kV overhead line, if the length of the medium-

voltage branch to be renewed is about 1000 m. The bars in the figure represent medium-voltage

branch lines in the actual network area.

0

5 000

10 000

15 000

20 000

25 000

0 0.5 1 1.5 2 2.5 3

Length of a 20 kV branch line [km]

Diff

ere

nce

in to

tal c

ost

s (i

nve

stm

en

ts, o

pe

x,

ou

tag

es)

[€/k

m]

0

2

4

6

8

10

12

14

16

18

20L

en

gth

of 2

0 k

V b

ran

ch li

ne

s in

the

targ

et a

rea

[k

m]

Length of 20 kV branch lines

20 kV UG

20 kV CC

20 kV OH

Figure 4.13. Comparison of network structures (LVDC vs. 20 kV OH line, 20 kV CC line and 20 kV UG

cable) and number of actual targets in the studied area (bars in the figure) (Lassila et al., 2009b).

88

In the case of LVDC technology, numerous challenges remain to be overcome. However, as

continuity is established in the field, the technology is taking steps forward and the criteria

related to the quality of supply are gaining ground, LVDC technology may become an essential

development tool in the network strategies in the future.

4.2.6. Remote-controlled disconnector

Large uniform network areas are challenging from the viewpoint of reliability of supply. A fault

occurring on a medium-voltage feeder starting from a primary substation is shown as an outage

to all customers on the feeder. In rural areas, the length of a feeder is on average 30–40 km, and

the number of customers on the feeder is typically 300–500. Although the number of faults

experienced by the customer can only be affected by adding circuit reclosers to the system or by

changing the network structure from overhead lines over to underground cables, disconnector

solutions are an efficient means to influence the duration of faults experienced by customers.

The better the network sections can be split into smaller parts, the easier the fault can be

isolated from the healthy network. If the disconnector is remote controlled, isolation of a fault

can be carried out faster than what is manually possible. The profitability of a single remote-

controlled disconnector can be determined fairly simply according to the example presented

below. In the example, there are already three manually operated disconnectors in the junction

of lines. The benefit (saving in time) of the remote control is estimated to be 0.8 h, if a backup

connection is not needed (the fault is on section C) or 0.4 h, if a backup connection is needed

(the fault occurs either on section A or B). The energy-weighted outage unit cost for the

duration of interruption is 4.3 €/kWh for the case area.

89

Fault frequency : 0.05 faults/km,aOperating time (manual disconnecor) : 1 hOperating time (remote-controlled) : 0.2 hand 0.6 h if reserve line is neededRepair time : 3 hRemote-controlled disconnector : 22 000 Eur(lifetime 25 years � 1560 Eur/a, p = 5 %)

Fault frequency : 0.05 faults/km,aOperating time (manual disconnecor) : 1 hOperating time (remote-controlled) : 0.2 hand 0.6 h if reserve line is neededRepair time : 3 hRemote-controlled disconnector : 22 000 Eur(lifetime 25 years � 1560 Eur/a, p = 5 %)

Primarysubstation

3 km, 40 kW

3 km, 60 kW

6 km, 200 kW3 km, 150 kW4 km, 150 kW 2 k

m, 1

50 kW

Remote-controlled disconnector ?

A

B

C

A reserve line

Fault, effect

Saving [h]before–after

Saving [€/a]

A B 1 – 0.6 = 0.4 (0.05 . 4 km) . 250 kW . 0.4 h . 4.3 €/kWh = 86 €/aC 1 – 0.6 = 0.4 (0.05 . 4 km) . 350 kW . 0.4 h . 4.3 €/kWh = 120 €/a

B A 1 – 0.2 = 0.8 (0.05 . 8 km) . 150 kW . 0.8 h . 4.3 €/kWh = 207 €/aC 1 – 0.2 = 0.8 (0.05 . 8 km) . 350 kW . 0.8 h . 4.3 €/kWh = 482 €/a

C A 1 – 0.2 = 0.8 (0.05 . 9 km) . 150 kW . 0.8 h . 4.3 €/kWh = 233 €/aB 1 – 0.2 = 0.8 (0.05 . 9 km) . 250 kW . 0.8 h . 4.3 €/kWh = 388 €/a

Total saving: 1 516 €/a

Fault, effect

Saving [h]before–after

Saving [€/a]

A B 1 – 0.6 = 0.4 (0.05 . 4 km) . 250 kW . 0.4 h . 4.3 €/kWh = 86 €/aC 1 – 0.6 = 0.4 (0.05 . 4 km) . 350 kW . 0.4 h . 4.3 €/kWh = 120 €/a

B A 1 – 0.2 = 0.8 (0.05 . 8 km) . 150 kW . 0.8 h . 4.3 €/kWh = 207 €/aC 1 – 0.2 = 0.8 (0.05 . 8 km) . 350 kW . 0.8 h . 4.3 €/kWh = 482 €/a

C A 1 – 0.2 = 0.8 (0.05 . 9 km) . 150 kW . 0.8 h . 4.3 €/kWh = 233 €/aB 1 – 0.2 = 0.8 (0.05 . 9 km) . 250 kW . 0.8 h . 4.3 €/kWh = 388 €/a

Total saving: 1 516 €/a

Figure 4.14. Example of outage cost benefits provided by a remote-controlled disconnector (Lassila et

al., 2005a).

By adding disconnectors to the network, only the duration of faults experienced by customers

can be reduced, not the number of faults. In the case of a circuit recloser, both the number of

faults and their durations can be reduced. Because of this essential difference, it is not possible

to determine universal feasibility ranges and curves for (remote-controlled) disconnectors

similarly as in the above examples for circuit reclosers and underground cabling. The

profitability of a disconnector solution is also strongly influenced by the number of backup

connections, in other words, to which extent the network is mesh operated. Therefore, the

profitability of a disconnector has always to be determined for each case individually.

4.2.7. Interdependence between network technologies and reliability

There is a strong interdependence between the reliability of electricity distribution and the

business income. In the strategic planning, information is required on the fault frequencies and

fault types in different operating areas when considering different network renovation

strategies. Table 4.2 illustrates the principles of the reliability effects of various network

solutions (effects on the fault rate, duration, short and long interruptions). The table shows that

the numbers of faults experienced by end-customers can be affected in particular by decreasing

90

the size of uniform supply sections by new primary substations or circuit reclosers or by

converting medium-voltage networks to low-voltage networks (1000 V technology). The

absolute numbers of faults occurring in the network can be affected only through technical

structural solutions, for instance by replacing overhead lines with underground cables. The

durations of faults experienced by customers can be reduced by investing on network

automation and fault restoration and repair organisation.

Table 4.2. Effects of different network technologies on the fault rate and duration (�� significant improvement, � some improvement, - slight or no improvement.

Number of sustained faults

Absolute pcs/customer

Duration of

sustained

faults/customer

Work

outages/

customer

Number of

reclosings/

customer

New primary substations - � � � - � �

UG cabling (medium- and low-

voltage networks)

� � � � - - � �

Covered conductors � � - - �

Construction by roadsides � � � - �

1000 V distribution � � � - - � �

Circuit reclosers - � � - - � �

Remote-controlled

disconnectors

- - � � - -

Backup connections - - � � � � -

Control room automation ( � ) ( � ) � � � -

Earth fault current suppression - - - - � �

Backup power - - � � � -

Cooperation � � � - -

In the strategy development work, it is necessary to be able to assess the cost and reliability

benefits of different alternatives at a sufficient accuracy. In practice, it will be challenging to

determine in detail the effects of different structural solutions on the development of reliability

indices; for instance, how much the fault frequency is assumed to decrease if a medium-voltage

line, located initially in the middle of a forest is transferred to the roadside or the line is

replaced with a covered conductor. If a distribution company already has statistical data on the

above-discussed technologies, this information can be utilised to some extent. However, the

emphasis is on national statistics compiled by central organisations in the field (Sener, Finnish

91

Energy Industries ET, Adato). Nevertheless, these statistics pose certain challenges, and they

are not always applicable as such owing, for instance, to the short history of the statistics, small

sample data and diverging practices and accuracy of statistics in the distribution companies. In

the future, information systems and substation automation play a central role in compilation of

more extensive and reliable statistics, which would facilitate the strategy work in distribution

companies. The needs related to these background data are described in more detail in section

4.5.

When considering the reliability of distribution networks, the effects of different network

solutions on the reliability of electricity distribution can be roughly described by the example of

Figure 4.15. In the figure, different network technologies are placed according to the time

required for implementation (x-axis) and change/improvement in reliability (y-axis). The figure

shows for instance that the most significant improvement in reliability can be reached by

extensive underground cabling of the medium-voltage network. However, implementation of

such a large project is time consuming. Automation solutions, instead (e.g. circuit reclosers,

disconnector automation, light primary substations) provide improvements in reliability already

in a shorter time span. In some cases, a 20–30 % improvement in the average outage duration

on the overhead feeder in one year has been achieved by implementation of automation

(Northcote-Green and Wilson, 2006). Nevertheless, underground cabling of the low-voltage

network is not considered to have a significant impact on customers’ statistical outage rates.

92

REMARKABLE

INSIGNIFICANT

TIME SCALE

TIME-CONSUMING IMPLEMENTATION

FAST IMPLEMENTATION

A CHANGE IN RELIABILITY

UNDERGROUND CABLING (MV NETWORKS)

RENOVATION WITH OLD TECHNOLOGY

COVERED CONDUCTORS

OVERHEAD CABLING

1000 V LOW-VOLTAGE SYSTEMSIMPLE, LOW-COST

PRIMARY SUBSTATIONS

RECLOSERSREMOTE-CONTROLLED DISCONNECTORS

EARTH FAULT CURRENT COMPENSATION

UNDERGROUND CABLING (LV NETWORKS)

BUILDING BY THE ROADSIDES

Figure 4.15. Effects of different network technologies on statistical (i.e., normal) reliability.

The network strategy process also delineates how the risk of blackout is taken into account in

the network development. In this context, a blackout is an extensive and long supply

interruption caused by trees or poles falling in a severe storm. In Figure 4.16, the same

technologies have been placed into the frame of reference similarly as in Figure 4.15, but with

respect to the risk of blackouts. The figure shows that the blackout risk can be minimised by

underground cabling of medium- and low-voltage networks. Now, the benefit of underground

cabling is based on the fact that damages caused by large storms do not have to be repaired in

the low-voltage network. Unlike in the previous figure, light and fast network automation

solutions do not improve reliability with respect to the risk of blackouts.

93

TIME SCALE

TIME-CONSUMING IMPLEMENTATION

FAST IMPLEMENTATION

RISK OF MAJOR STORMS

LOW RISK LEVEL

HIGH RISK LEVEL

UNDERGROUND CABLING (BOTH MV AND LV NETWORKS)

COVERED CONDUCTORS

BUILDING BY THE ROADSIDES

OVERHEAD CABLING

1000 V LOW-VOLTAGE SYSTEM

SIMPLE, LOW-COST PRIMARY SUBSTATIONS

RECLOSERSREMOTE-CONTROLLED DISCONNECTORS

EARTH FAULT CURRENT COMPENSATION

RENOVATION WITH OLD TECHNOLOGY

Figure 4.16. Effects of different network technologies in the case of major storms.

4.3. Calculation methodology for the analysis of long-term cost and reliability effects

The detailed cost and reliability effects of network choices related to the network strategy can

only be analysed by applying the results of the operating environment and technology potential

surveys to the actual electricity distribution environment. The network area to be analysed has

to be large enough to ensure the reliability of the analysis. On the other hand, the area to be

analysed has to be small enough so that the effects of parameter variation can be detected fast

and easily. It is also of utmost importance to find such a network section that adequately and

well describes the operating environment and the structure of the distribution system and

thereby makes it possible to bring the results to a more general, company level. The issues

related to the selection of areas to be analysed are addressed in more detail in Chapter 5.

94

Compared with the feasibility studies for different technologies presented in section 4.2, the

analyses made for actual network sections provide more truthful results about the application

potential of different network technologies. The local boundary conditions set by the operating

environment become more visible when the potentials of different network technologies are

analysed with the accuracy of a medium-voltage feeder. For instance, in the feasibility studies

of underground cabling, it is possible to include cost components that better correspond to

reality as the cabling installation costs can be specified according to the soil analyses of the

operating environment. The feasibility of underground cabling depends highly on whether the

soil allows cable installation by ploughing, or traditional excavation methods are required. This

information is specified further when plans are drawn up for the target areas. Furthermore,

distribution management systems (DMS) and fault location records can be utilised to define

fault frequencies that more accurately describe the area under observation; this way, the

development of outage costs can be assessed more accurately.

The cost and reliability analyses made for target network areas require suitable analysis tools

and calculation methodology. Calculation methodology related to individual network

technologies were introduced and discussed in section 4.2. As the above introduction to these

technologies showed, outage costs have a significant weight in the feasibility studies. One of the

major challenges in strategic planning is to determine the cost and reliability effects of different

network structural solutions and development alternatives at a general level without going into

too detailed and time-consuming analysis. The development of strategic planning in this

direction has partly been restricted by the incomplete analysis methodology and limited analysis

tools of the present asset management systems (such as network information systems,

distribution management systems and condition monitoring systems). Enlightening examples of

large strategy-related issues are: is there room for network automation in the present electricity

distribution network, how does wide-scale underground cabling affect the costs, reliability

indices, the company’s result, distribution fees paid by the customers or the network’s

susceptibility to blackouts. So far, such large issues have not been dealt with in the long-term

network development and asset management, but the approach has been limited to single

targets. However, too detailed an analysis does not give a reliable picture of the total effects.

Furthermore, carrying out a highly detailed analysis for the entire company is so time and

resource consuming that it is not possible in practice. The iterative and interactive nature of the

process makes the analysis even more complicated. Unreliable and insufficient initial data

95

together with the limitedness of the calculation parameters to correctly describe the operating

environment inevitably lead to an iterative analysis process. Therefore, the methodology and

analysis tools have to be flexible to enable alteration of the initial data. For the strategic

planning as a whole, it is vital to recognise the interdependencies between different factors

involved in the distribution networks.

4.4. Description of the calculation system

To enable the development of the strategy process, a calculation system has been developed for

research purposes. In the following, an asset management system developed as a tool for a

researcher is introduced; the core results of this dissertation are based on application of this

system.

4.4.1. Objectives and purpose of the system

The targets in the system development have been better manageability of large masses of data

required in the electricity distribution business, assessment of the reliability of information,

understanding of the mutual interaction between different factors (and parameters) and strategy-

related cost and reliability calculation. The system developed here does not function

independently, but requires a large amount of data from other information sources such as the

distribution company’s network information system, customer information system, distribution

management system and condition management system. The information systems currently in

use in distribution companies serve well the different subtasks related to asset management, yet

they are not able to produce holistic results to support strategy-level decision-making. To reach

the set research targets, a system has been developed to combine initial data and subresults into

compilations useful for the purposes of asset management. The developed asset management

system includes a number of different calculation elements starting from determination of

feasibility ranges for specific network technologies to determination of the value of large

network masses and reliability calculation.

96

4.4.2. Initial data

“The quality and quantity of data produced in strategic analysis will affect both the cost and the

quality of strategic decisions” (Grünig and Kühn 2006, p. 53). Successful asset management

calls for extensive and reliable initial data and efficient data processing. In the analysis system

developed in this work, the initial data comprises technical network data of the distribution

network, customer data, cost data and other long-term statistics. Both the technical and

economic background data are collected into the asset management system according to the

primary substations and medium-voltage feeders. The feeder approach has been taken to avoid

collection and allocation of data at too detailed (and time-consuming) a level, but

simultaneously, to guarantee that the accuracy of data is sufficient enough for strategic analysis.

Traditionally, reliability calculation has concentrated on the analysis of the medium-voltage

network, as 80–90 % of the outages experienced by customers originate from the medium-

voltage network.

The present practices concerning compilation of outage statistics support the above feeder

approach. Data from the distribution transformers and low-voltage networks are gathered and

allocated to the respective medium-voltage feeder. Distribution transformers are not treated as

single components but they and their end-customers always belong to some medium-voltage

feeder as shown in Figure 4.17.

Maa-kaapeli

Kauko-ohjatut erottimet

Manuaali-set erottimet

Pylväs-muuntamot

Puisto-muuntamot PJ-verkkopituus [km] Asiakkaiden lukumäärät ryhmittäin

Asema Johtolähtö [km] Yht. Metsä Pelto Tienvarsi Yht. Metsä Pelto Tienvarsi [km] Runko Thaara Phaara Määrä [kpl] Määrä [kpl] [kpl] [kpl] Avojohto AMKA Maakaapeli Kotitalous Vapaa-ajan as.

YHTEENSÄ: 413.2 306.8 119.4 159.3 28.1 53.1 18.6 26.9 7.6 53.3 21 252 406 67 47 1 146 158 10 828 0

Kallbäck KLB_J07 INGMAN30.455 19.742 7.5 8.4 3.8 5.217 0.821 2.8223 1.57365 5.496 76 22 2 2 28 1 0 34 4 1.06 345.1 25.507 1 430 0

Kallbäck KLB_J08 KALKSRAND13.747 10.49 8.7 1.1 0.7 2.936 2.0318 0.9042 0 0.321 60 40 0 0 7 1 0 18 1 5.541 53.7 1.779 532 0

Kallbäck KLB_J09 SÖDERKULLA6.263 1.695 0.8 0.2 0.7 2.341 0 2.341 0 2.227 90 10 0 0 9 1 0 6 3 1.605 7.8 1.919 105 0

Kallbäck KLB_J10 GUMBOSTRAND28.851 20.277 17.6 2.7 0.0 1.546 1.546 0 0 7.028 42 53 5 3 9 1 0 27 4 5.265 92.6 9.996 767 0

Kallbäck KLB_J11 BOX17.115 16.919 2.8 12.3 1.9 0.171 0 0.171 0 0.025 32 60 8 1 8 1 0 20 1 1.373 42.8 1.266 338 0

Kallbäck KLB_J12 GALTHAGEN4.544 2.312 0.5 0.5 1.3 1.1 0 0.682 0.418 1.132 42 58 0 0 5 1 0 4 3 0.296 11.4 3.346 282 0

AsiakastiedotPJ-muuntopiirit

1

Lähdöllä pylväs-katkaisija?

Johto-lähdön yhteis-pituus

Johtotiedot

Avojohto [km] Päällystetty avojohto [km]

Erottimet ja pylväskatkaisimet

Jako käyttötarkoituksen perusteella [%]

EiKyllä

Ei

Ei

Ei

Ei

Ei

Ei

Low-voltage networks- Customer numbers- Customer groups- Annual energy- Network information

z

z

20 kV

110/20 kV

Distribution substations

- Distribution transformer and substation information

- Age and condition information

Medium-voltage networks- Line structure- Line lengths- Switchgear - Interruption statistics

Switches- Structural and functioning

principles- Operation times

Feeder 1

Feeder 2

Figure 4.17. Principle of the network structure applied in the asset management system and an extract of

the initial data table.

97

In reality, for instance because of different amount of backup connections and network

automation systems, the supply areas of distribution transformers of the medium-voltage feeder

do not experience supply outages of equal length. In the strategic analysis, however, it is

possible to apply simplified and average estimates of fault durations at a feeder level. Figure

4.18 illustrates the background information and calculation systems used in the network

analyses.

Assessment of load

development

Network data

Power flow calculation (peak powers, losses), compensation considerations

Outage statistics, normally open points, operating times

Number of customers, kWh data, consumer group data, development of energy consumption

Network age and condition data

Reliability + major storm

analyses

Network unit costs, work costs, development of the operating area (land use planning etc.)

Development needs for transmission and

transformation capacity

SAIFI, SAIDI, MAIFI, outage costs

Present and replacement value of the network

Determination of network investment

history and value

Strategy alternatives

Network operation and maintenance costs

Network information system

Distribution management and operation control systems

Customer information system

Maintenance system

Other sources

SAIFI, SAIDI, outage costs, distribution fee, profit of owner, depreciations etc.

Figure 4.18. Information flows related to the strategy process. All the elements required in the process are

not included in detail in the illustration.

A detailed list of initial data collected into the system is presented in Table 4.3.

98

Table 4.3. Detailed list of initial data collected into the system.

Network data

Low-voltage network: lines, transformers, distribution substations, protection equipment, distribution cabinets

Medium-voltage network: lines, disconnectors, switches

Primary substations: main transformers, switchgear and controlgear, compensation equipment, automation

Others: other network assets (e.g. information systems, kWh meters)

Customer data

Consumption of electrical energy

Customer group information (households, agriculture, public, services, industry)

Cost data

Unit prices of network components (EMA)

Costs of losses

Outage cost parameters for different fault types and customer groups (EMA)

Maintenance costs

Fault repair costs

Fault statistics for different network structures

Long supply interruptions

Planned outages

High-speed and delayed autoreclosings

Age and condition information of network components

Operation times

Switching times of disconnectors (manual/remote-controlled)

Fault repair time and duration of a planned maintenance action for different network structures (overhead line,

cable, covered overhead line)

Calculation parameters

Lifetimes (network components)

Work costs (maintenance, fault repair)

Interest rate

Reference period

Load growth (area-specific)

99

4.4.3. Calculation operations of the asset management system

As described above, the asset management tool developed in this work utilises partly the results

produced by other systems. The reason for doing so is that there has been no need to introduce

such subfunctions to the asset management system that are already well established in the

present distribution network applications. Such are for instance the calculation results related to

load flow calculation (loads on lines and transformers, network losses, voltage drops,

compensation considerations) and calculations based on fault current calculation. The most

essential calculation functions of the developed asset management system are listed below.

- Calculation of reliability indices (SAIFI, SAIDI, MAIFI)

- Outage cost calculation (average and customer group weighted)

- Operation and maintenance cost calculation

- Evaluation of the development of loss costs in different network structures

- Calculation of the replacement value of the network

- Calculation of the present value of the network

- Effects of different development options on the distribution fee

- Definition of the techno-economic feasibility range of a circuit recloser

- Definition of the techno-economic feasibility range of underground cabling of medium-

voltage network, a covered overhead line, and transfer of lines to roadsides

- Determination of the investment history

- Assessment of future annual investment needs based on the investment history

The key reason for developing the asset management system has been the arising need for

flexible treatment of large network entities. Load flow and fault current calculations as such do

not assist in evaluating the cost and reliability effects of strategic network decisions. The asset

management system developed in this work makes it possible to consider the effects of different

strategic policy lines on large network entities. The background data gathered into the system

are used in various subapplications, such as in distribution system reliability calculation and

determination of the network value.

100

4.4.4. Determination of the network value

From the company’s business perspective, one of the key targets is to determine the value of the

electricity distribution infrastructure and its development in an appropriate way. The importance

of this target is emphasised by the fact that the calculation of the allowed return on capital by

the Energy Market Authority has been based on the determination of the network value. The

asset management system takes into account both the replacement value and the present value

of the network. The replacement value is the value of an asset when replacing an existing asset

with the same quality of construction. Correspondingly, replacement value of the distribution

network is the construction cost of the distribution network at the current level of costs.

Determination of the replacement value is based on the network component quantity data

submitted by the company and the network component unit price data defined by the Energy

Market Authority as shown in Table 4.4.

Table 4.4. Example of network component unit prices by the Energy Market Authority (EMA, 2009a).

Distribution substations Unit price [€/pcs.]

1-pole-mounted distribution substation 4 8502-pole-mounted distribution substation 6 6304-pole-mounted distribution substation 7 220Pad-mounted, type 1 (outside maintained) 27 490Pad-mounted, type 2 (inside maintained) 35 010Building-mounted distribution substation 47 620Special distribution substations 80 990Satellite-type distribution substations 16 800

Figure 4.19 illustrates the distribution of capital by component groups in an example

distribution company. The figure shows that a significant proportion (almost 70 %) of the

network assets (replacement value) is tied up in low- and medium-voltage networks. Hence,

approaches focusing on these component groups in the long-term development will have a

strong influence on the total value of the network and thereby the development of the business.

In addition to the formation of the network value, all component groups have an effect on the

accumulation of the operational and outage costs.

101

110/20 kV primary substation

10 %

110 kV lines6 %

20/0.4 kV distribution substations

15 %

20 kV medium-vo ltage lines26 %

0.4 kV low-voltage lines43 %

- Aerial bundled cables (AMKA)- Underground cables- Bare overhead lines- Distribution cabinets

- Distribution substation structures- Distribution transformers- Transformer disconnectors

- Bare overhead lines- Covered conductors- Line disconnectors- Underground cables- Cable joints and terminations

- Primary transformers- 110 kV equipment- 20 kV equipment- Earth fault arc suppression coils

Figure 4.19. Value of the network assets by component groups for an example company.

For a distribution company, besides compilation of network component quantity data, a more

challenging task has been to determine the ages of the network components. These age data are

used as the basis for the determination of the present value of the distribution network. The

present value in turn plays a key role in the calculation of allowed return on capital. Present

value is determined by the current ages and lifetimes of the network components (Eq. (4.10)).

RVPV ⋅

−=

timelife

age1 (4.10)

PV = present value of the network

age = average age of the network

lifetime = techno-economical lifetime of the network

RV = replacement value of the network

Considering the allowed return, it is desirable that the network age remains low, in other words,

the present value stays high. If no investments are made in the network, the network will

continue ageing and the company’s allowed return becomes lower. To avoid reduction in the

present network value, the annual investment level of the distribution company has to be at least

equal to the depreciation level defined from the network replacement value. Investments made

in the network can be categorised into new or replacement investments depending on whether

the investments increase the volume of the network or old components are just replaced by new

ones. Unlike in the determination of replacement value, in regard to calculation of the present

network value, all investments are equal, and it is not necessary to classify them into new or

102

replacement investments in advance. If needed, the classification can be made afterwards by

investigating the network component data recorded in the network information system. An

increase in the quantity of network components and thus in the network replacement value

compared with the previous year indicates that new investments have been made in the

network. By calculating the difference between the replacement value of the reference year and

the preceding year and by taking into account possible changes in the unit prices of network

components, we obtain a rough estimate of the proportion of new investments in the net

investments. In the calculation model, the present value of the network is obtained according to

Eq. (4.11).

T

RVINVPVPV n

nnn

11

−

− −+= (4.11)

PVn = present value of the network in the current year

PVn-1 = present value of the network from the previous year

INVn = investments on current year

RVn-1 = replacement value of the network from the previous year

T = average depreciation period

Depreciations on the distribution network are computed as straight-line depreciations from the

network replacement value. When the depreciations are calculated from the network

replacement value during the depreciation period, an average lifetime of network, computed

based on the techno-economic lifetimes of the network components, is used in the calculations.

Thus, component lifetimes play a key role in the determination of the present value of the

network and in the methods for determining depreciations of network investments. The

component lifetimes are based on surveys compiled by the Energy Market Authority (Partanen

et al., 2002). From the lifetime range provided by the authority, the distribution companies may

select such a value that best describes the company’s area of operation and demand for network

renovation. Essential factors that have an impact on the component lifetimes are the load

growth and development of the infrastructure in the area. In areas of intensive growth, the

techno-economic lifetimes are notably shorter than what the actual technical age of the

components would allow, because components have to be replaced by new ones for reasons

other than reaching the end of the technical lifetime. If the growth in electricity consumption

remains stable or the growth is slow, the techno-economic lifetimes of network components are

close to the technical lifetimes of the components. In terms of national economy, it is profitable

to keep the components in the network as long as they are still in order and operating.

103

In the calculation system developed, the age and lifetime data of the network can be taken into

account by component groups. Component-group-specific age data enable the presentation of

the investment history as shown in Figure 4.20. The figure shows how much has been invested

in different components in the course of time in the company history. In the example figure, the

component groups have been limited to low-voltage network components.

0

100 000

200 000

300 000

400 000

500 000

600 000

700 000

1957 1959 1961 1963 1965 1967 1969 1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Jälle

enha

nkin

ta-a

rvo

[€]

Pj-ilmajohdot

Pj-kaapelit

Muuntajat

Muuntamot

30 - 40 a> 40 a

Rep

lace

men

t val

ue [€

]

Low-voltage lines

Low-voltage underground cables

Distribution transformers

Distribution substations

Figure 4.20. Investment history of the example company; the low-voltage network.

When a component reaches its techno-economic lifetime, the present value of the network

component reduces to zero, and it no longer has an impact on the calculation of allowed profit.

Thus, the mechanism provides an incentive to renew the oldest network sections as they reach

their lifetime.

Based on the investment history and the chosen component lifetimes, it is possible to determine

the future investment needs in a distribution company. Figure 4.21 shows how much the

company should invest in the network in years to come, if the outdated components are to be

replaced by new ones as they reach their lifetime. Often, there are also such components on the

network that are outside the techno-economic lifetimes defined by the authority. In the case

illustrated in Figure 4.20, these components exceeding the official lifetimes are planned to be

replaced at an even rate during the first ten years. After this, there are no longer any such

components on the network that would not have lifetime (and present value) left. The figure

also depicts the level of straight-line depreciations determined on the basis of the network

104

replacement value and average lifetime. This level represents the amount of money that has to

be invested in network renovation in order to keep the value of the network at the present level.

The figure shows also that in some years, the investment level is lower than the calculated

straight-line depreciation (the replacement value decreases) while in some years, the investment

level is higher than the straight-line depreciation (the present value increases). The actual age

data of the component groups based on component installation years are used as background

information in the analysis.

0

100 000

200 000

300 000

400 000

500 000

600 000

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Sa

ne

era

usi

nve

sto

inn

it [€

/a]

0,4 kV maakaapelit(asennus)0,4 kV ilmajohdot

Muuntajat

Muuntamot

DEPRECIATION LEVEL

Ren

ovat

ion

inve

stm

ents

[€/a

]

Low-voltage underground cables

Low-voltage lines

Distribution transformers

Distribution substations

Figure 4.21. Future investment needs based on the historic data of the example company.

By investigating the investment history of all network component groups, it is possible to

determine the present value of the entire distribution network and its development in the future.

Figure 4.22 depicts an alternative of the development of the network present value. In the

example, it is assumed that the company replaces the components by new ones as they reach

their techno-economic lifetime. In the initial situation, the average age of the network is slightly

above half of the average lifetime (present value percent is 46 %). The dashed line in the figure

depicts the annual investment need resulting from replacement of components. The calculations

are based on age and lifetime data of the components. The need for replacement of components

is based on the investment history, where investments documented for different years may vary

considerably. In practice, the target is usually to schedule any large-scale renovation actions to

span several years in order to evenly distribute the annual investment costs among the years.

105

34 %

36 %

38 %

40 %

42 %

44 %

46 %

48 %

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Nyk

ykäy

ttöar

vopr

osen

tti

0

200 000

400 000

600 000

800 000

1 000 000

1 200 000

1 400 000

Inve

stoi

nnit

Pre

sent

val

ue o

f th

e ne

twor

k [%

]

Inve

stm

ents

[€/a

]

Investments

Present value

Figure 4.22. Development of the present value of the example company.

4.4.5. Reliability calculation

Reliability calculation and network outage costs play a key role in the asset management system

developed in this work. Determination of outage costs is based on the fault rate of different

network structures, valuation of harm caused by outages (outage costs) and on the company

personnel’s ability to react to and recover from fault situations (amount of network automation,

switching speeds and repair times). In outage cost calculation, both short and long supply

interruptions are taken into account. In addition to faults, planned outages (such as network

maintenance) are taken into consideration in the calculation. Besides determination of outage

costs, the system calculates various technical (quality) indices based on the above (e.g. SAIFI,

SAIDI, MAIFI). Reliability calculation of an electricity distribution system is based on a large

amount of background information and different calculation parameters. The equations applied

in outage cost and quality index calculation are presented in section 4.5.4.

As groundwork for development alternatives, certain reference costs have to be determined for

outages, in other words, the present outage cost level of the network has to be defined. To

determine this reference level, the reliability calculation is first performed for the present

network structure and topology. After this, the structural data of the network are altered for

106

instance by converting overhead line sections into underground cables or by adding network

automation devices to the network. After the changes, the reliability analysis is carried out again

for the new network structure. If the operation and outage cost benefit is now higher than the

investment cost difference between these two alternatives, then it is economically justifiable to

include the chosen development alternative in the network strategy. The differences in the

operating conditions within the company’s area of operation lead to diverging solutions in the

outage cost considerations. To this end, the analysis tool provides an opportunity to analyse

large network entities simultaneously. The present network information systems do not include

this option; in these systems, calculations have to be made for each node section individually.

The results obtained from outage cost calculation can be utilised at least from two viewpoints;

for operative purposes, the outage costs can be determined for different fault types for instance

according to a distribution substation or a feeder. This way, the network operation can be

directed towards a state where the total outage costs caused by a fault are minimised. In practice

this means that customer groups that have a high outage cost value (such as a public load and

industry) are separated from network sections that are vulnerable to faults, or restoration of

supply is guaranteed as soon as possible. Figure 4.23a shows the outage costs by distribution

substations for one-hour outages in an example distribution company. Figure 4.23b presents the

outage costs by feeders.

107

Feeder 7Long interruption: 284 € + 2 955 €/hHSAR: 142 €/pcsDAR: 361 €/pcs

Feeder 2Long interruption: 930 € + 8 854 €/hHSAR: 512 €/pcsDAR: 995 €/pcs

Feeder 3Long interruption: 1 589 € + 14 366 €/hHSAR: 992 €/pcsDAR: 1 693 €/pcs

Feeder 1Long interruption: 1 242 € + 12 343 €/hHSAR: 704 €/pcsDAR: 1 333 €/pcs

Feeder 6Long interruption: 4 858 € + 52 013 €/hHSAR: 2 625 €/pcsDAR: 4 826 €/pcs

Feeder 4Long interruption: 399 € + 3 690 €/hHSAR: 229 €/pcsDAR: 465 €/pcs

Feeder 5Long interruption: 148 € + 1 646 €/hHSAR: 60 €/pcsDAR: 194 €/pcs

110/20 kV substationLong interruption: 9 450 € + 95 868 €/h

110/20 kV

Squares: Outage cost in distribution substation in 1-hour interruption:< 100 €/h100 – 500 €/h500 – 1000 €/h1000 – 2000 €/h> 2000 €/h

Lines: Installation year of the cable:< 19701970 – 1980 1980 – 19901990 – 2000> 2000

a) b)

Figure 4.23. Example of a) outage costs by distribution substations for a one-hour fault and b) outage cost

caused by different fault outages according to the number and duration of the outage.

The figure shows such distribution substations and feeders that are particularly vulnerable to

faults and require special attention, and where restoration of electricity supply in the occurrence

of a fault in the medium-voltage network has to be guaranteed as fast as possible.

Figure 4.24 illustrates the value of economic harm (outage cost) of a one-hour outage for the

distribution substations of the previous example. The figure shows for instance how a one-hour

fault occurring in the medium-voltage network may result in outage costs of thousands of euros

in certain supply areas of the distribution transformers. On the other hand, the figure illustrates

such supply areas of the distribution transformers that, in the occurrence of a fault in the

distribution substation itself, cause high outage costs in the supply area of the distribution

transformer in question. Thus, by taking into account this and the high ages of the distribution

substations (a higher risk of failure), the order in which the distribution substations are

renovated can be optimised. In the case of distribution substations, in addition to age, the risk of

failure depends on load rate and number and duration of possible overload situations. Constant

overloading weakens the transformer’s insulating capacity and increases the risk of failure.

108

Hence, actual load information together with age data has to be taken into account when

planning the renovation order.

0

10 000

20 000

30 000

40 000

50 000

60 000

0 10 20 30 40 50

Age of transformer [a]

Out

age

cost

s fo

r di

strib

utio

n su

bsta

tion

in th

e ca

se o

f a o

ne-h

our

faul

t [€/

h]

Figure 4.24. Example of outage costs for distribution substations in the case of a one-hour fault. In the

occurrence of a fault in the medium-voltage network, the outage costs will be particularly high in the

circled distribution substation. Owing to its high age, the distribution substation itself is susceptible to

faults.

Yet another aspect in the reliability calculation and renovation planning is the network

approach. Now, such line sections are determined on the network that are most prone to faults

and that, in the occurrence of a fault, cause significant outage costs. In this approach, the

investments can be directed to targets where their effect on the total outage costs of the network

is at highest. Such targets can be for instance overhead line sections close to urban areas.

Replacing overhead lines with underground cables or separating overhead lines as protection

zones of their own by network automation improves the reliability of supply for the customers

belonging to the same supply circuit. Figure 4.25 provides an example of such a case.

Considering the reliability of supply for the customers at the substation end of the feeder, both

renovation alternatives presented above bring the same outcome. Underground cabling

decreases the probability of a failure, while automation provides a means to restrict the fault to

a certain network section so that the fault is not seen outside this section. In the example case,

for the customers at the far end of the feeder, network automation is of no help, as in the

occurrence of a fault, they belong to the network section that is separated from the supply. The

109

reliability of supply for the customers at the far end of the feeder can be improved only by

reducing the absolute number of faults, for instance by underground cabling, or by otherwise

cutting down the number of faults occurring in the forest section of the feeder. Another option

is to arrange a backup connection for the customers at the far end of the feeder and to add

network automation between the risky (vulnerable) network section and customer at the far end

of the feeder.

z

z

110/20 kVFeeder 1

Feeder 2

a) b)

Figure 4.25. a) Separating a network section that is vulnerable to faults and causes significant outage costs

to constitute a protection zone of its own or b) replacing the line section with an underground cable.

In reliability considerations, special attention has to be paid to cross-effects of different

reliability investments. Underground cabling that was initially found to be techno-economically

feasible, may turn unprofitable if sufficient amount of network automation is added to the

network, and vice versa. Thus, investments are not independent of each other. On the other

hand, solutions may not necessarily rule each other out, if the outage cost level on the feeder is

very high. Hence, an optimum solution is often reached by combining different network

technologies. In the asset management system developed in this work, several development

alternatives can be taken into account simultaneously. The structure of the feeder can be

adjusted according to the needs for instance by replacing a traditional overhead line with a

covered conductor or an underground cable, or by adding manually or remotely controlled

disconnectors and circuit reclosers.

110

4.4.6. Determination of long-term costs in distribution system operation

A key target in the research has been to develop a system concept capable of determining long-

term costs of distribution system operation. The costs of a distribution system comprise costs

related to the capital costs, network operation and maintenance costs, and loss and outage costs

(listed as follows):

1) Investment costs

2) Loss costs

3) Outage costs

4) Repair and maintenance costs

5) Financing costs

These types of cost are made commensurate with each other by means of cost accounting in

order to be able to assess and compare the profitability of different network solutions in actual

situations. Alternatives are to determine the annual amount of lump-sum costs by applying the

annuity method, or to calculate the amount of annual recurrent costs (such as losses) by the

discounting method for the whole reference period.

A majority of the fixed annual costs in distribution networks consist of the capital costs of

transformers, lines and other components. Capital costs are further divided into financing costs

and costs caused by depreciations on investments (annual depreciations). Network investment

costs include labour, material and transport costs and other costs directly related to network

construction. Investment and financing costs are of significant weight in total costs of the

network. In addition to capital costs, fixed costs include network upkeep and maintenance costs.

Local conditions have an influence on the costs of the distribution network; network planning is

based on amounts and locations of loads on the network. Further, land use, the target level for

reliability and environmental aspects all have an impact on the network topology. In addition to

111

these, the value of the distribution network is affected by company-specific planning principles.

The distribution company has little power over environmental conditions; limitations related to

land use, such as land use planning, can be considered to belong to these. Environmental

conditions cause costs in network construction for instance in terms of compensations paid for

land use for line construction. During the lifetime of the network, the environmental effects are

mainly shown in the network maintenance and outage costs.

In addition to the general interest rate level, capital costs are affected by the network lifetime

and the age of the existing network at the moment of renovation. If it is necessary to renovate

an existing network before its calculated lifetime has been reached, the company balance sheet

will include depreciations on the old network that is out of operation but also investments in the

new network structures. Therefore, correct timing of renovations is of utmost importance in

network construction.

Besides the outage costs discussed in the reliability calculation section, costs of quality of

supply realised in the distribution company include standard compensations paid to customers if

an outage exceeds 12 hours. This blackout cost component is a useful tool in analysing the

ability of different investment strategies to manage blackouts. Empirical data gathered from

previous blackouts can be efficiently utilised when estimating future blackout costs.

Figure 4.26 depicts the results of long-term cost calculation for the present state in the network

and for a development alternative in an example case. The outage costs are presented together

with investment, financing, major storm costs and operational costs of two different network

technologies. The cost components have been calculated according to the principles presented

above. When comparing the sizes of the bars, we can see that in the development alternative,

special attention is paid to the reliability of networks. Furthermore, the development alternative

seems to reduce the network’s vulnerability to blackouts. The plan made for the target area

applies such network solutions that have a positive effect on the outage costs but are

simultaneously slightly less expensive than the traditional structural solutions.

112

0

10 000

20 000

30 000

40 000

50 000

60 000

70 000

80 000

90 000

1 2

Development strategy

Co

sts

of t

he

str

ate

gy

[k€

] Opex

Outages

Major storms

Financing

Investments

Figure 4.26. Total long-term costs of two network solutions.

In the strategic decision-making, outage costs constitute part of the total costs. Depending on

the network technology applied, fault frequencies and the area under consideration, these costs

may play a very significant role. Distribution of outage costs into the categories of short and

long outages as well as planned and unplanned outages of network alternatives is illustrated in

Figure 4.27.

0

2 000

4 000

6 000

8 000

10 000

12 000

Strategy 1 Strategy 2

Out

age

cost

s [k

€]

Delayed autoreclosings

High-speed autoreclosings

Planned interruptions

Long interruptions

Figure 4.27. Long-term outage costs of two network solutions.

113

4.5. Background information required in the process

Background information plays a crucial role in the network strategy process. Erroneous or

deficient initial data hamper the strategy work and may lead to wrong decisions. Here, the term

‘background information’ refers both to various statistical data and different subcalculation

results as shown in Figure 4.28.

Load flow calculation

Background information and parameters for

strategy analyses

- Voltage and power losses and operational costs

- Transmission and transforming capacity� development needs

Fault current calculation

- Fault-prone line sections� Reinforcement needs

Parameters

- Unit prices of components (EMA)- Price of losses- Outage cost parameters for different

interruptions and different customer groups (EMA)

- Fault rates- Repair and reconnection times- Life-times (network components)- Work costs (maintenance, fault repair) - Interest rate- Calculation period- Load growth

Statistics

- Fault statistics- Repair and reconnection times- Current measurements- Area-specific load forecasts- Network age and condition information

Figure 4.28. Background information required in the strategy process.

In the asset management, the network information system plays a central role. Network

information systems have traditionally been used in power flow and fault current calculations.

A network information system serves asset management also by providing various statistical

data. The determination of network asset and thereby assessment of allowed return is based on

component quantity and age data. These data are typically available from the network

information system. In addition to the network information system, other information systems

utilised in the strategy work are distribution management, condition monitoring and customer

information systems.

4.5.1. Power flow calculation

Development of electricity distribution business calls for comprehensive knowledge of the

various needs related to the task. A crucial boundary condition determining the development

comes from the present transmission and transforming capacity and the future load growth

forecasts on the network. A persistent and long-standing industry as it is, electricity distribution

114

requires long-term analyses, extending up to 20 years from the present. Regional load growth

forecasts require for instance detailed study of the land use planning in towns and other

municipalities.

From the very early days of information system applications in electricity distribution

companies, determination of losses and voltage drops, that is, load flow calculation, has been

considered to constitute one of the most essential calculation targets. The results of load flow

calculation are applied to asset management especially when estimating the sufficiency of

transmission and transforming capacity in the future, in other words, whether it is necessary to

build new primary substations in the company’s area of operation, or whether the demand for

power can be covered with the present network structures. As the weight of operational costs is

increasing in the official regulation, also the role of loss costs gains importance in asset

management. Load flow calculation provides background information for increasing

transforming and transmission capacity if for instance the risk of large outages increases as a

result of insufficient/limited capacity. Figure 4.29 lists the initial data in power flow calculation

and application targets for the calculation results.

ENERGY INFORMATION

-Energy information (billing, CIS)

-Load models (nationwide, customer-specific)

ENERGY INFORMATION

-Energy information (billing, CIS)

-Load models (nationwide, customer-specific)

NETWORK INFORMATION

-Primary transformers (110/20 kV)

-Medium-voltage network

-Distribution substations

-Disconnectors

-Low-voltage network

-Normally open points

NETWORK INFORMATION

-Primary transformers (110/20 kV)

-Medium-voltage network

-Distribution substations

-Disconnectors

-Low-voltage network

-Normally open points

MEASUREMENTS

-Primary transformers

-Medium-voltage feeders

-Distribution substations (peak current)

-Voltage measurements

MEASUREMENTS

-Primary transformers

-Medium-voltage feeders

-Distribution substations (peak current)

-Voltage measurements

CALCULATION PARAMETERS

-Voltage

-Load growth

CALCULATION PARAMETERS

-Voltage

-Load growth

Voltages and voltage dropsVoltages and voltage drops

Initial data for power flow calculations

Results and targets of power flow calculations

Load rate of conductorsLoad rate of conductors

Load rate of primary and distribution transformers

Load rate of primary and distribution transformers

Backup power analysesBackup power analyses

Optimisation of normally open points of the network, economic operation of the network

Optimisation of normally open points of the network, economic operation of the network

Investment of transmission and transformation capacity

Investment of transmission and transformation capacity

Relay settings of the networkRelay settings of the network

Outage cost calculationsOutage cost calculations

(CIS=customer information system)

Figure 4.29. Initial data and targets of power flow calculation.

115

The accuracy of the results of power flow calculation has a significant influence on the future

investment decisions. The reliability of results depends on the initial data used in the power

flow calculation; network and customer data and calculation parameters. Considering

calculation parameters, determining the regional development of load levels is one of the most

challenging tasks. Owing to the long lifetimes of network investments, an error in the estimate

for the annual development of the load level may significantly influence the calculation results.

The correctness and accuracy of the results of power flow calculation have to be checked and

assessed before the results can be applied to long-term network planning. This assessment stage

is critical always when large network investments or changes in the network structure or loads

are considered. Figure 4.30 depicts the initial data, the assessment process and further use of the

results.

RESULTS FROM POWER FLOW CALCULATION

RESULTS FROM POWER FLOW CALCULATION

MEASUREMENTS� Load rate of primary transformers� Load rate of feeders� Load rate of distribution transformers� Voltage levels at the end of feeders

MEASUREMENTS� Load rate of primary transformers� Load rate of feeders� Load rate of distribution transformers� Voltage levels at the end of feeders

ENERGY� kWh data

� Load models

ENERGY� kWh data

� Load models

NETWORK� Component data� Topology, supply areas

NETWORK� Component data� Topology, supply areas

COMPARISON

CHECK LIST� Customer energy information (reasonable kWh data)� Topology of the network (simulation vs. real situation)� Quality of load models � Remeasurements for feeders and distribution

substations

CHECK LIST� Customer energy information (reasonable kWh data)� Topology of the network (simulation vs. real situation)� Quality of load models � Remeasurements for feeders and distribution

substations

DIFFERENCE SIGNIFICANT BETWEEN SIMULATION AND MEASUREMENTS

RESULTS O

K

FURTHER PROCESSING OF POWER FLOW CALCULATION RESULTS

� Backup power analyses (primary substation faults, feeders)

� Increase in transmission and transformation capacity � Reliability calculations� Protection analyses and relay settings� Optimisation of normally open points of the network,

economic operation of the network

FURTHER PROCESSING OF POWER FLOW CALCULATION RESULTS

� Backup power analyses (primary substation faults, feeders)

� Increase in transmission and transformation capacity � Reliability calculations� Protection analyses and relay settings� Optimisation of normally open points of the network,

economic operation of the network

RECALCULATION OF POWER FLOW RECALCULATION OF POWER FLOW

RESULTS OK

DIFFERENCE SIGNIFICANT BETWEEN SIMULATION AND MEASUREMENTS

Figure 4.30. Assessment process of the power flow calculation results.

The results of power flow calculation are applied for instance to determine investment needs

from the perspective of transmission or transforming capacity and in loss and outage cost

calculation. Figure 4.31 illustrates an example of regional load growth estimates and

distribution of loads by primary substations.

116

+ 23.2

+13.6+ 0.5

+ 13.2

+1

+7.1

+8.1

+ 4.2

+1.6 +1.8

+ 1

+ 0.9

+ 1.9

+ 0.1

+ 1.1

+ 0.7

+ 0.6

+ 0.9

+ 0.6+ 0.6

+ 1

+ 13

+ 7

+2.2

+ 0.5

Load forecast 2007–2025 (maximum forecast)

PS 1

PS 2

PS 3

PS 4

PS 1 - 31.5 MVA2007: 20 MW2010: + 8 MW (max. + 10 MW)

2015: + 24 MW (29) *2020: + 43 MW (51) *2025: + 54 MW (64) *

PS 2 - 25 MVA2007: 13 MW2008: 5 MW2010: + 1 MW2015: + 2 MW2020: + 3 MW2025: + 5 MW

PS 3 - 20 MVA2007: 18 MW2010: + 2 MW (3)

2015: + 4 MW (5) *2020: + 7 MW (8) *2025: + 11 MW (13)*

PS 4 - 31.5 MVA2007: 0 MW2008: 8 MW2010: + 2 MW (3)

2015: + 8 MW (11)

2020: + 17 MW (22) *2025: + 37 MW (50) *

* = need to increase trasformer capacity

Load growth [MW]Substation 2010 2015 2020 2025PS 1 8 24 43 54PS 2 1 2 3 5PS 3 2 4 7 11PS 4 2 8 17 37

14 38 69 107

Load growth [MW]Substation 2010 2015 2020 2025PS 1 8 24 43 54PS 2 1 2 3 5PS 3 2 4 7 11PS 4 2 8 17 37

14 38 69 107

PS = 110/20 kV primary substation

Figure 4.31. Forecast for the increase in demand for electric power [MW] in the example area.

The results describing loading of the distribution network serve already as such in the long-term

development of the network. The results of power flow calculation may set a boundary

condition on the strategy work; even if the age or reliability of the network did not require

renovation, insufficient transmission capacity may compel certain actions. In such a case, an

increase in capacity is planned to be carried out so that it best serves also the other targets set in

the strategy.

4.5.2. Fault current calculation

Similarly as the results of load flow calculation, the results of fault current calculation carried

out by network information systems are applied to long-term development of the distribution

network. In the strategic planning, fault current calculation can be applied for instance to

guarantee that a primary substation construction project, which is found necessary based on

network reliability requirements, does not lead to excessive conductor replacement needs

117

because of increasing fault currents. The weight of short circuit current calculation has

nevertheless decreased in the past few decades. Previously, the medium-voltage network had to

be reinforced because of increased fault currents. This was the situation particularly in rural

areas, where the main transformer capacity at the primary substations had to be increased and

the mains of the medium-voltage networks had to be reinforced as the voltage drops were

increasing on the network. This led to a significant increase in fault currents and problems in

particular on branch lines with low power and small conductor cross-section. Figure 4.32

presents the initial data and application targets of the results of fault current calculation. A

successful short-circuit calculation requires extensive initial data of the lines, relays and the

supplying main grid.

POWER FLOW DATA

-MV network power flow

POWER FLOW DATA

-MV network power flow

NETWORK DATA

-Transmission network

-Primary transformers (110/20 kV)

-Protection relays

-Medium-voltage network

-Circuit breakers and reclosers

-Network topology

NETWORK DATA

-Transmission network

-Primary transformers (110/20 kV)

-Protection relays

-Medium-voltage network

-Circuit breakers and reclosers

-Network topology

CALCULATION PARAMETERS

-Calculation voltage

CALCULATION PARAMETERS

-Calculation voltage

Modification needs in relay settingsModification needs in relay settings

Initial data in short-circuit calculations Results and application targets of short-circuit calculation

Backup power analysesBackup power analyses

Effects of an increase in primary transformer capacity

Effects of an increase in primary transformer capacity

Line sections without short-circuit withstand capacity

Line sections without short-circuit withstand capacity

Figure 4.32. Initial data and application targets of short-circuit calculation.

From the perspective of electrical safety and reliability, earth fault calculation produces

valuable information for the long-term development. The expanding use of underground cabling

increases fault currents in the medium-voltage network. In poor earthing conditions, this may

mean facing the limits of electrical safety requirements and increased investments in earthing or

compensation of earth fault currents. As a single investment, compensation equipment is an

expensive one. The decreasing effect of the equipment on earth fault current has a positive

influence on the reliability of the network (reclosings). Thus, in the company’s investment

strategies, compensation equipment has to be regarded as an investment improving the

reliability of the network.

118

4.5.3. Network age and condition data

The age and condition of the network have a crucial impact on the company development plans,

in particular from the viewpoint of the development schedule. The prevailing situation in the

field is that the ages of networks are high and extensive renovations are required in the near

future. For the network strategy, a sufficiently detailed and extensive database for instance on

the age and mechanical condition of the wood poles in the overhead network is required. This

information together with the reliability statistics and loading of the network is applied to

allocate investments to targets requiring special attention. Figure 4.33 introduces some

principles of processing of the condition monitoring data.

INSPECTION DATA

INSPECTION DATA

NETWORK DATA� MV network� Distribution transformers� Circuit breakers, reclosers and disconnectors� Pole data

NETWORK DATA� MV network� Distribution transformers� Circuit breakers, reclosers and disconnectors� Pole data

CHECK-UP LIST� Repair of detected defects� Comparison with the previous inspection: have the

detected defects been repaired? Do the same defects occur repeatedly ath the same locations?

CHECK-UP LIST� Repair of detected defects� Comparison with the previous inspection: have the

detected defects been repaired? Do the same defects occur repeatedly ath the same locations?

OK (Nothing to repair)

CONDITION MONITORING DATA� Input of condition data into NIS or condition

monitoring system� Listing of targets critical with respect to age, condition

and loads� Renovation planning

CONDITION MONITORING DATA� Input of condition data into NIS or condition

monitoring system� Listing of targets critical with respect to age, condition

and loads� Renovation planning

INSPECTIONINSPECTION

DEVELOPMENT PLANNING� Linking the condition and age data and the list of critical

components to the planning process and network renovation

� Solutions to recurrent problems

DEVELOPMENT PLANNING� Linking the condition and age data and the list of critical

components to the planning process and network renovation

� Solutions to recurrent problems

DEFICIENCIES DETECTED IN INSPECTION

CRITERIA� Consistent, unambiguous and justifiable criteria and

procedures� Updating of the criteria

CRITERIA� Consistent, unambiguous and justifiable criteria and

procedures� Updating of the criteria

Figure 4.33. Processing of the condition monitoring data in asset management.

Figure 4.34a provides an example of the present state of a distribution network with the

installation year data of the wood poles. The figure shows that already the present state calls for

extensive investment in the renewal of the network. In the example case, almost a third of the

wood poles in the network have exceeded the 40 years’ lifetime. In addition, considering the

allowed return and the distribution business regulatory model, incentives for renovation are

significant. A high pole age alone does not tell whether the line requires instant renovation.

Figure 4.34b presents the results of a condition survey for the area in question. The figure

119

shows that the major problems are limited chiefly to the wood poles installed before the mid-

1970s.

0

100

200

300

400

500

600

< 5 5 - 10 11 - 15 16 - 20 21 - 25 26 - 30 31 - 35 36 - 40 41 - 45 46 - 50 51 - 55 > 55

Ikä

Num

ber

of p

oles

Age

26 % 29 %

1934 1951 1954 1957 1960 1964 1968 1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004

0

50

100

150

200

250

300

350

Pyl

väid

en m

äärä

[kp

l]

Kyllästysvuosi

LAHOA YLI 20 MM

LAHOA 10-20 MM

LAHOA 2-10 MM

LAHOA 0-2 MM

TERVE

Year of impregnation

Num

ber

of p

oles

Diameter of rot

Over 20 mm

10–20 mm

2–10 mm

0–2 mm

Healthy

a) b)

Figure 4.34. Example of the age and condition data of wood poles on medium-voltage lines.

By combining age and condition data, valuable information is obtained on network sections

requiring special attention. When considering only minimising of investment costs, it would be

advisable to replace the wood poles by new ones right when they reach their lifetime and the

limits of sufficient operating condition. This has been the common practice in Finland until the

turn of 2000s, and it is partly the reason why the present distribution network includes poles of

almost all ages, as shown in Figure 4.35.

> 40 years

30 – 39 years

20 – 29 years

10 – 19 years

< 10 years

Figure 4.35. Example of the age data of wood poles on medium-voltage lines.

Considering the reliability of the network, a problem in a pole renewal of this kind is that the

network topology and locations of the lines remain unchanged; the number of supply outages

caused by storms will not decrease if only the poles are replaced by new ones without

transferring the lines to safer areas, such as fields or roadsides.

120

4.5.4. Reliability calculation

Reliability calculation (outage cost calculation) plays a key role in the present network

strategies and distribution business (Sand et al., 2004). In the strategy work, reliability

calculation aims at analysing the large-scale effects of different network solutions on the indices

describing the reliability of distribution networks (such as SAIFI, SAIDI, MAIFI) and outage

costs. In reliability calculation, challenges are posed by different cross effects of actions; for

instance, network automation added to the medium-voltage network influences the economic

feasibility of underground cabling and vice versa. Network renovation usually consists of a

number of different structural renewals, and therefore, their mutual effects have to be known. In

this work, reliability issues have already been considered from the perspective of individual

technologies for instance for the case of a circuit recloser and the comparison underground

cable – overhead line in sections 4.2.2 and 4.2.3. Figure 4.36 provides some initial data needed

in the reliability calculation and the most relevant application targets of the calculation results in

the long-term network development.

POWER FLOW DATA

-MV network power flow

POWER FLOW DATA

-MV network power flow

NETWORK DATA

-MV network

-Distribution transformers

-Circuit breakers, reclosers and disconnectors

-Network structure and topology (forest, field, roadside)

NETWORK DATA

-MV network

-Distribution transformers

-Circuit breakers, reclosers and disconnectors

-Network structure and topology (forest, field, roadside)

CALCULATION PARAMETERS

-Outage cost parameters (€/kWh, €/kW)

-Fault frequencies

-Load growth

CALCULATION PARAMETERS

-Outage cost parameters (€/kWh, €/kW)

-Fault frequencies

-Load growth

Line sections critical with respect to reliability of supply

Line sections critical with respect to reliability of supply

Initial data in outage cost calculation Results and application targets of outage cost calculation

Reserve power analysisReserve power analysis

Optimisation of normally open points of feeders, economical operation of the network

Optimisation of normally open points of feeders, economical operation of the network

Need for an increase in transmission capacityNeed for an increase in transmission capacity

Protection relay settings on the networkProtection relay settings on the network

Assessment of the need for an increase in network automation

Assessment of the need for an increase in network automation

NETWORK OPERATION DATA

-Normally open points

-Fault disconnection time (manual/remote-controlled)

-Fault repair time

-Fault statistics

NETWORK OPERATION DATA

-Normally open points

-Fault disconnection time (manual/remote-controlled)

-Fault repair time

-Fault statistics

Outage costs by feeders and distribution districts

Outage costs by feeders and distribution districts

Figure 4.36. Initial data and application targets of reliability calculation.

The principles of reliability calculation in the asset management system are based on a radially

operated medium-voltage network. As most of the outages (80–90 %) of the outages

experienced by electricity consumers originate in the medium-voltage network, the faults

occurring in the low-voltage network are neglected in the calculation. The number of outages,

121

their duration and outage costs can be calculated by the following equations (Mäkinen et al.,

1990); the subscript j denotes electricity consumer and the subscript i network component from

the set of the components I.

Outage rate ∑∈

=Ii

ij ff (4.12)

Annual outage time ∑∈

⋅=Ii

ijij tfU (4.13)

Average outage duration

j

j

jf

Ut =

(4.14)

Non-distributed energy jjjj PtfE ∆⋅⋅= (4.15)

Outage costs [ ]∑∈

∆+=Ii

jijijjjij PttbafC )( (4.16)

The above equations can be used to calculate the indices that describe the reliability for each

electricity consumer. The first equation describes the total number of outages, which can be

calculated by determining the failure rates fi of the components i in the medium-voltage feeder.

For instance, if the total line length is 120 km, and the failure rate of the sustained faults on the

overhead lines is 5 faults/100 km per annum, each consumer experiences in average six faults in

a year, depending on the number of faults occurring on the lines.

The outage cost for each electricity consumer can be calculated with Eq. (4.16). The calculation

of costs is based on the approach of Eq. (4.13); that is, first, we determine the number and

duration of faults caused by each network component to a consumer. The outage costs

122

experienced by the electricity consumer depend on the number and duration of faults and the

power and type of the electricity consumer. The annual mean power is usually assumed as the

outage power. The outage costs are usually estimated by a constant term proportional to the

power (parameter a in Eq. (4.16)) and by a term proportional to the outage time (non-distributed

energy; parameter b in Eq. (4.16)). The amount of outage costs also depends strongly on the

type of the electricity consumer; for instance, an outage cost caused for instance to services is

manifold when compared with the costs caused to domestic customers (Järventausta et al.,

2003). Figure 4.37 depicts determination of outage costs for a single supply area of a

distribution transformer; this is a procedure used in the asset management system also.

Number of Mean power of Mean power Outages/customer, acustomers Energy [MWh] the group [kW] [kW/as] Outage time, planned 3.5 h

Domestic 2 25 2.9 1.43 Outage time, fault 1 hAgriculture 2 52 5.9 2.97 Number of outages, fault 5 pcsIndustry 1 80 9.1 9.13 Number of outages, planned 1 pcsPublic 1 11 1.3 1.26 High-speed automatic reclosings 10 pcsService 1 14 1.6 1.60 Delayed automatic reclosings 2 pcs

High-speed DelayedOutage cost values [€/kW] [€/kWh] AR [€/kW] AR [€/kW]

Domestic fault 0.36 4.29 0.11 0.48planned 0.19 2.21

Agriculturefault 0.45 9.38 0.2 0.62planned 0.23 4.8

Industry fault 3.52 24.45 2.19 2.87planned 1.38 11.47

Public fault 1.89 15.08 1.49 2.34planned 1.33 7.35

Service fault 2.65 29.89 1.31 2.44planned 0.22 22.82

Outage costsDomestic Agriculture Industry Public Service Sum Percentage

Outage time, planned 42.9 195.0 781.3 66.5 167.4 1253 62.7 %Outage time, fault 6.3 28.5 104.7 9.3 36.5 185 9.3 %Number of outages, fault 5.1 13.4 160.7 11.9 21.2 212 10.6 %Number of outages, planned 0.5 1.4 12.6 1.7 0.4 17 0.8 %High-speed automatic reclosings 3.1 11.9 199.9 18.8 21.0 255 12.7 %Delayed automatic reclosings 2.7 7.4 52.4 5.9 7.8 76 3.8 %

61 257 1312 114 254 1998 100.0 %

CENSOutage timeMean powerNumber of customersCost ⋅⋅⋅=

CENSOutage timeMean power of the customersCost ⋅⋅=

OR

Figure 4.37. Calculation of outage costs for the electricity consumers of a single supply area of a

distribution transformer (Järventausta et al., 2003).

Calculation of outage costs is affected by the parameters applied in the analyses; for instance, as

outage parameters, it is possible to use the common national values determined by the Energy

Market Authority, or company- or target-specific customer distribution can be used in the

reliability calculation, as shown in Figure 4.37.

There are various uncertainty factors related to the fault statistics, outage cost calculation and

selection of structural solutions. For instance, the network fault statistics and distribution

123

management systems involve a challenge; in the case of planned outage costs (work outage),

the distribution management system may record a single operation carried out in a certain target

as several work outages if more than one connections are made in the target for example in the

same day. From the viewpoint of a customer, this is correct when all individual outages and

restorations of supply and the actual time without supply are taken into account with an

accuracy given by the distribution management system. However, considering the assessment

of the reliability of a network structure, it is problematic that the same target can be recorded as

three to five separate work outages at worst. Therefore, in the strategy work, special attention

has to be paid to the determination of parameters used in the analyses.

Similarly as the adequate usability and reliability of the results of load flow calculations

constitute the basis for the strategy work, the results of the reliability calculation have to be

critically assessed before applying them to practice. To this end, sufficiently extensive and

versatile statistics on different network solutions are needed to be able to assess the initial data

and calculation results. Figure 4.38 presents the initial data, the assessment process and the

further use of the results.

OUTAGE COST CALCULATION AND RESULTS

OUTAGE COST CALCULATION AND RESULTS

POWER FLOW DATA� Power flow results for

the MV network

POWER FLOW DATA� Power flow results for

the MV network

NETWORK DATA� MV network� Distribution transformers� Circuit breakers, reclosers and

disconnectors� Network structure and topology

NETWORK DATA� MV network� Distribution transformers� Circuit breakers, reclosers and

disconnectors� Network structure and topology

CHECK-UP LIST� Does the network structure used in calculations correspond

with the actual situation (cabling rate of feeders etc.)?� Do the actual fault statistics cover a long-enough time span?

CHECK-UP LIST� Does the network structure used in calculations correspond

with the actual situation (cabling rate of feeders etc.)?� Do the actual fault statistics cover a long-enough time span?

SIGNIFICANT DIFFERENCE (between fault frequencies applied to calculations and actual values)

RESULTS OK(fault frequencies applied to calculations correspond with actual values)

FURTHER USE OF OUTAGE COST RESULTS� Assessment of outage costs� Line sections critical with respect to reliability of supply� Optimisation of normally open points of feeders, economical

operation of the network� Renovation planning� Protection settings of the distribution network � Assessment of the need for an increase in network automation

FURTHER USE OF OUTAGE COST RESULTS� Assessment of outage costs� Line sections critical with respect to reliability of supply� Optimisation of normally open points of feeders, economical

operation of the network� Renovation planning� Protection settings of the distribution network � Assessment of the need for an increase in network automation

NETWORK OPERATION DATA� Normally open points� Fault isolation time (manual, remote)� Fault repair time� Fault statistics

NETWORK OPERATION DATA� Normally open points� Fault isolation time (manual, remote)� Fault repair time� Fault statistics

ANALYSIS OF CALCULATED AND ACTUAL FAULT FREQUENCY

STATISTICS

ANALYSIS OF CALCULATED AND ACTUAL FAULT FREQUENCY

STATISTICS

DEVELOPMENT PLANNING� Add automation, modify the network structure, adjust

location of lines → adjust fault frequency in calculations� Perform outage cost calculation again

DEVELOPMENT PLANNING� Add automation, modify the network structure, adjust

location of lines → adjust fault frequency in calculations� Perform outage cost calculation again

OUTAGE COST PARAMETERS(€/kW,a and €/kWh)

Figure 4.38. Assessment process of the reliability of outage cost calculation.

124

125

5. Strategic decision-making

In this chapter, the target is to illustrate how the development strategies introduced in Chapter 4

and the concept approach presented in Figures 2.4 and 2.5 can be applied to the strategy work in

an actual distribution network environment (Figure 2.5 is repeated as Figure 5.1 for the

convenience of the reader). The results presented here are examples from actual distribution

networks; however, it is emphasised that the results cannot be generalised as such. In the

strategy process, the objective in the decision-making stage is to establish the models of

operation that have been found feasible in the network analyses and agreed upon in the

negotiations between the owner and the operative management of the distribution company.

Successful strategic decision-making calls for extensive surveys on the operating environment

and analyses of the potentials of different network technologies. The decision-making addresses

issues related to the scope and schedule of application of different technologies to the long-term

network planning; see Figure 5.1. The decision-making is based on cost and reliability analyses

of the strategies.

Strategic analyses

Long-term plan

Implementation of strategic decisions

Potential use of technologies (%)- Transfer of overhead lines to roadsides (25 %)- Underground cabling (10 %)- Remote-controlled disconnector substations, circuit

reclosers (1 pcs/feeder)- 1000 V technology (30 %)

Cost effects of the technologies- Transfer of overhead lines to roadsides (50 km/a, 1 M€/a)- Underground cabling (5 km/a, 250 k€/a)- Remote-controlled disconnector substations, circuit

reclosers (20 pcs/a = 250 k€/a)- 1000 V technology (50 km/a, 1 M€/a)

A long-term plan for the example area and the whole distribution company taking into account the strategic decisions made in the process.

How a single development technology e.g. underground cabling is implemented in practice?

- Underground cabling: starting from the feeder sections most vulnerable to faults, or from the oldest sections, or by proceeding from the substation downstream from the feeder

- Network automation:…

What are the effects of different development methods?

- Costs, reliability, distribution fee, allowed return

Strategic decisions

Reliability effects of the technologies fault duration rate reclosings

- Transfer of overhead lines to roadsides (x) x x- Underground cabling (x) x x- Remote-controlled disconnector

substations, circuit reclosers x/x -/x -/x- 1000 V technology (x) x x

Owners’ objectives- Reduction in SAIDI 20–40 %- Increase in the present value of the network from 45 to 50 %

Calculation parameters- Unit costs: x €/km, y €/pcs- Losses: 50 €/MWh- Outage cost values: EMA- Interest rate: 5 %- Lifetime: limits set by EMA (maximum)- Load growth: 1–3 %/a (by regions)- Fault rates: x pcs/100km,a (overhead line)…- Switching times: 60 min (manual), 10 min (remote) - Repair times: 4 h (cable), 2 h (overhead line)…

- Main technologies- Owner’s perspectives

(amount and schedule of investments)

Figure 5.1. (Figure 2.5 repeated) Network strategy process: from strategic decisions to a long-term plan.

126

The electrotechnical state, reliability, age and condition of the distribution networks have to be

taken into account in the strategic decision-making; these factors significantly affect the

strategic planning. For instance, new primary substations added to the network to increase the

transmission capacity will reduce the need for network automation, which is otherwise found

profitable in the strategy work. Cross effects are significant in network development, and they

have to be taken into account regularly in the strategy work (Grünig and Kühn, 2006, p. 85). In

the decision-making stage, the calculation principles and parameters as well as their mutual

effects have to be recognised and understood by the parties involved in the process.

Furthermore, it is necessary to assess and understand what kind of large-scale effects the results

obtained in the potential surveys of different network technologies may have on the company

business. For example, a network technology, which has obtained a 5 % application potential in

the feasibility study (e.g. 1000 V technology) may turn out to have a 30 % potential if the initial

data such as costs and calculation parameters are varied in the analyses. A need for variation

may arise from internal needs, such as changes in cost structures, or outside the company, such

as changes in the outage cost parameters in the regulatory model. Thus, in order to be viable,

strategic decision-making has to be based on various sensitivity analyses.

5.1. Strategy analyses

In the strategy work, a survey on the operating environment of the distribution company

together with an analysis of alternative development technologies draws the focus on those

issues that have the strongest influence on the company business in the future. There may be a

vast number of network development options available, and therefore, these choices have to be

limited by strategic decisions before introducing the options into the actual development

process. The decision-making is supported and facilitated by the cost and reliability analyses

introduced in Chapter 4; such tools are selected that best contribute to reaching the objectives

set by the distribution company. The cost analysis of different development alternatives is based

on the principles presented in section 4.4.6. Lump-sum investment costs are scheduled for

instance by applying the annuity method for the whole network lifetime, or alternatively, the

periodic costs such as operation and maintenance costs are converted to the present value to

enable comparison.

127

A development strategy may comprise several different network technologies. The development

strategy, the total costs of which are the lowest, may include for instance underground cabling

of the medium-voltage network and transfer of overhead lines to roadsides, network automation

and 1000 V low-voltage technology. The development strategies may vary considerably

between different distribution companies. For instance, considering the 1000 V technology, the

geographic conditions and location of a distribution company significantly affect the feasibility

of the technology. Figure 5.2 illustrates the proportion of low-loaded branch lines suitable for

1000 V technology in the entire distribution network in some example companies. The figure

shows that differences between companies may be considerable in the feasibility of the

technology, and consequently, the contents of the development strategy may vary substantially

among companies. For company 1, in the strategic sense, the 1000 V has a marginal role as a

replacement of the medium-voltage network, as only 8 % of the present medium-voltage

network includes low-loaded branch lines suitable for 1000 V technology. In companies 2 and 5

instead, the proportion of suitable branch lines is about 40 % of the total medium-voltage

network. Although this figure only gives an indication of the theoretical maximum

exploitability of the technology, the proportion of network suitable for the development

alternative in question is so large that the issue has to be considered in the strategy process.

0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

Company 1 Company 2 Company 3 Company 4 Company 5

Low -loaded branchlines

Heavy-loaded branchlines

Main trunks

Figure 5.2. Exploitability of the 1000 V technology in the example distribution companies.

The contents of the strategy are not necessarily the same for the entire operating area of the

distribution company but the composition and application of the strategy may vary depending

128

on the network technologies applicable in practice. For instance the issue of underground

cabling is strongly dependent on soil properties and opportunities to apply cost-efficient

ploughing technology. In some other network targets, the selection of network development

technologies and other technical decisions may be directed by a strong load growth and severe

weather phenomena in the area. Figure 5.3 illustrates an example calculation result of the long-

term costs of different network development alternatives in an example distribution company.

The costs have been calculated for the whole network lifetime, in this case for 40 years.

0

10 000

20 000

30 000

40 000

50 000

60 000

70 000

80 000

1 2 3 4 5 6Network Strategy

To

tal

cost

s o

f th

e st

rate

gy

[k€

]

OPEX

OUTAGE

FINANCING

INVESTMENTS

Development strategy

Tot

al c

osts

of

the

stra

tegy

[k€]

Figure 5.3. Annual costs of the investment strategies divided into investment, operational and outage costs.

Based on the owners’ objectives and development prospects in the operating environment, a

distribution company can emphasise certain cost components, or alternatively, omit them from

the strategic consideration altogether. The major single uncertainties related to the cost

components presented in the above figure concentrate on reliability and blackout costs.

Moreover, attention has to be paid to environmental factors presented in Chapter 3 in particular

when the operating environment of the distribution company is susceptible to the effects of

climate change. From the perspective of network operation, the annual variation in adverse

weather phenomena may be large, and estimating the scope of climate change for instance 20

years ahead will be extremely challenging. Severe and frequently occurring blackouts may have

a decisive effect on the total long-term costs of overhead line solutions.

129

Generally speaking, the role of outage costs is significant and will gain further importance in

the long term. Along with the general development in society, the requirements for higher

reliability will be emphasised; this will show particularly in weighting of outage cost

parameters. Therefore, considering reliability parameters, it is necessary to carry out different

sensitivity analyses to get as comprehensive overall picture as possible. Figure 5.4 illustrates

how a change in outage parameters affects the costs of alternative development methods in an

example network area. The present level of outage cost (100 %) depicts the situation before the

update of outage cost values at the turn of year 2006. The new outage cost values have nearly

doubled compared with the values ten years ago.

0

20 000 000

40 000 000

60 000 000

80 000 000

100 000 000

120 000 000

140 000 000

160 000 000

180 000 000

100%200%

300%400%

500%600%

700%800%

900%1000%

1100%1200%

1300%140

0%150

0%

Keskeytyskustannusparametrien arvostuksen muutos

Total costs

of the strategy [€]

Valuation of outage costs (100 % = present valuation level)

Renovation with the present technology

Transfer to roadsides

Lines next to road + 1 kV technology

Underground cabling

Lines next to road with covered conductors + 1 kV

Figure 5.4. Effect of changes in the valuation of outage costs on the total costs of different investment

strategies. 100 % refers to the situation before the update of outage cost values at the turn of year 2006

(Matikainen, 2006) and (Lassila et al., 2007b).

The above figure emphasises the importance of the sensitivity analyses made as part of strategic

calculations. Development in the operating environment and initial data may have a crucial

effect on the strategic decisions. In addition to the sensitivity analysis of outage cost parameters,

it is advisable to vary for instance the unit prices of network components, load growth forecasts

and fault frequencies in the strategic calculation. By sensitivity analyses, it is possible to better

take into account such uncertain initial data, which, when changing, would strongly affect the

strategic choices. The example illustrated in the above figure shows for instance that if the case

network is renovated with the present technology, an optimum level in costs will not be reached

at any time. On the other hand, construction of a full-scale underground cable network would be

reasonable and justified, if the valuation of outage costs were four- to fivefold compared with

the latest outage cost values. For this case network an optimal solution is reached by applying

130

several different technologies in the development of the distribution network. It is also worth

pointing out here that the cost analysis of network strategies presented is not universal but the

analysis has to be made for each case individually. In any case, it is advisable to consider

whether the best results can be reached by putting emphasis on network automation or by

concentrating on the development and utilisation of the primary technology.

5.2. Strategic decisions

As a result, the strategy analyses produce the main technology choices for long-term

distribution network development. The strategic decisions call for guidelines from the owners

concerning annual investment appropriations, objectives for reliability, and development targets

set for distribution fees and return. The methodology presented in the dissertation has been

applied in an actual distribution network environment. In one of the case companies, the

strategy process produced for instance the following guidelines and principles concerning the

network technologies:

- Underground cabling of the medium-voltage network will be applied only to urban

environments.

- The overhead lines in rural areas will be renovated to the roadsides either as overhead

lines or underground cables at a rate based on the natural ageing of the lines.

- The network automation rate will be increased by adding remote-controlled disconnectors

and circuit reclosers to the network. Network automation will be concentrated on those

targets where, according to the reliability calculation, the investments are the most

profitable.

- 1000 V technology is applied to the renovation of low-voltage networks and low-loaded

medium-voltage branch lines.

In particular, the above technologies will be applied to the renovation of those targets where

investments are required owing to the electrotechnical state, ageing, mechanical condition or

reliability of the distribution network. The principles of prioritisation are discussed in detail in

the following section.

131

5.3. Implementation of strategic decisions

When a distribution company has, after comprehensive analyses, decided upon a certain set of

network technologies, the next task is to address various questions related to the practical

implementation of the network development, such as where or at what kinds of targets to start

the renovation, how much is invested at an annual level, and what are the eventual effects for

instance on reliability indices and distribution fees. Selection of development targets, in other

words, prioritisation, can be based for instance on age and condition data of the network,

electrotechnical calculations or reliability statistics as shown in Figure 5.5.

KALLBÄCK

BoxGalthagen

> 40 years

30 – 39 years

20 – 29 years

10 – 19 years

< 10 years

> 8 points

7 – 8 points

5 – 6 points

3 – 4 points

< 3 points

Age

1934 1951 1954 1957 1960 1964 1968 1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004

0

50

100

150

200

250

300

350

Pyl

väid

en m

äärä

[kp

l]

Kyllästysvuosi

Mechanical condition

Reliability

Transmission capacity

MASSBY

KALLBÄCK

Box

Masby:

Söderkulla5.9 MW2.8 %

Masby:

Hitå7.6 MW5.2 %

PSS:

1 MW

PSS:

0.5 MW

Gumbostrand

Galthagen

Ingman

OLD OVERHEAD LINE

Load and line layout

INVESTMENT ORDER

Figure 5.5. Prioritisation of targets based on initial data.

Reliable and extensive initial data on the distribution network facilitate the prioritisation of

development targets (Brown et al., 2005). However, applying several initial data at a time

involves a challenge of how to weight different factors in decision-making and selection of

technologies. All the initial data cannot be converted into commensurate cost components

presented in euros; therefore, various ranking systems have to be developed to assign scores to

the compared cost parameters in order to support the decision-making. If the network

132

renovation has been postponed for a long time already, a cost-efficient renovation order can be

found reliably by concentrating first on the aged feeders. The prioritisation of targets may prove

challenging if the network sections do not essentially differ from each other with respect to the

initial data and development criteria. An example of background feeder data for prioritisation of

development targets is given in Table 5.1.

Table 5.1. Background feeder data for prioritisation of development targets.

MV networks (20 kV) LV networks (0.4 kV) Customers Energy Peak power Wood poles Outages

Total [km] UG [km] Substations Length [km] [GWh/a] [kW] Number Age [faults/100km,a] Costs [€/a]

Feeder 1 30.5 5.5 38 370.7 1 486 20.2 6 000 374 29 4.6 39 737

Feeder 2 13.7 0.3 19 55.5 538 10.3 3 200 201 28 7.8 57 345

Feeder 3 6.3 2.2 9 9.7 112 4.8 2 300 61 29 3.0 3 971

Feeder 4 28.9 7.0 31 102.5 781 6.1 2 100 327 35 5.8 24 572

Feeder 5 17.1 0.0 21 44.1 353 5.4 1 700 256 33 3.9 10 070

Feeder 6 4.5 1.1 7 14.8 287 3.2 1 100 51 30 4.1 2 426

Feeder 7 59.1 18.3 42 110.7 1 010 7.1 2 400 612 34 5.4 21 215

Feeder 8 0.3 0.3 5 0.0 1 22.8 3 800 0 20 1.0 473

Feeder 9 19.2 12.3 11 30.7 292 6.6 4 800 104 25 4.7 6 879

Feeder 10 36.3 6.8 48 106.6 956 16.5 5 400 441 28 6.9 52 617

Feeder 11 20.9 7.5 38 77.6 2 278 36.2 8 800 200 34 2.3 50 873 Figure 5.6 illustrates a case where the renovation criterion and the technology choice have been

the fault rate on the feeder, the feeder length and the network structure (overhead

line/underground cable), respectively, in an example distribution company. In this reliability-

oriented renovation example, short, already partly underground-cabled medium-voltage feeders

in urban areas are laid underground altogether, and network automation is added to long feeders

in rural areas to cut the outage costs. This kind of an approach may be adopted for instance in a

network where the reliability of supply poses a challenge but the network age does not call for

renovation yet. If, in addition to reliability, also the network age calls for actions, adding

automation to the network does not abolish the need for renovation. Now, besides adding

network automation to the network, the lines have to be renewed by replacing the poles by new

ones and by transferring the lines to the roadsides, and by applying covered overhead

conductors or underground cables.

133

0

2

4

6

8

10

12

14

16

18

0 10 20 30 40 50 60 70

Johtolähdön pituus [km]

Vik

ataa

juus

[kpl

/100

km,a

]

Feeder 2 (39 %)

Feeder 1 (44 %)

Feeder 5 (5 %)

Feeder 4 (3 %)

Feeder 3 (11 %)

Feeder 6 (1 %)

CABLING

NETWORK AUTOMATION

Feeder name (underground cabling rate,%)F

ault

rat

e [f

ault

s/10

0km

,a]

Length of the feeder [km]

Figure 5.6. Allocation of reliability investments to different feeders.

The distribution company’s investment strategy includes analyses of the actual implementation

of different network technologies (how the technologies are applied, and in which order). For

instance, implementation of underground cabling can be carried out by starting from those

feeder sections that are most vulnerable to faults, or by proceeding from the substation

downstream. Figure 5.7 illustrates an example result of an analysis in which the reliability

effects of different cabling techniques on a feeder are presented as a function of time.

0,00

0,50

1,00

1,50

2,00

2,50

0 5 10 15 20 25 30 35 40

Fault rate [faults/customer,a]

Year

Cabling-B

Cabling-A = cabling starting from the feeder sections most vulnerable to faults

Cabling-B = cabling proceeding from the substation downstream towards the end of the feeder

Cabling-C = pole-mounted circuit recloser at the beginning of a long branch line + cabling proceeding from the substation downstream towards the end of the feeder

Cabling-A

Cabling-C

Figure 5.7. Development of fault (outage) rate (SAIFI) in different cabling strategies. Forest rate 10 %,

investment costs (€) of all alternatives are the same (adapted from Haakana et al., 2009).

134

Prioritisation of targets may also be based on the progress in locations of loads. Figure 5.8

depicts the locations of loads on a rural feeder away from the line route, along the roads. The

rather straightforward choices made in route planning for overhead lines were based on material

savings targets in the past decades. The development of built-up areas and loads on the network

is mainly concentrated along roadsides. In the large-scale network renovation, it is necessary to

consider on which principles the choices for line routes are based. If the feeder renovation is

carried out by underground cabling or by transferring the line to the roadside, the distribution

system simultaneously shifts closer to the point at which the loads are actually concentrated.

110/20 kVPrimary substation

OLD OVERHEAD LINE

= Customer

= 20/0.4 kV distribution substation

Figure 5.8. Renovation of an old overhead line by shifting the line closer to the area in which the loads are

concentrated.

After the completion of the prioritisation process, potential feeders that meet different

renovation criteria are investigated; cost and reliability analyses are performed for the feeders

starting from the oldest network sections. Now it is time also to make decisions on the schedule

of renovations, that is, whether it is desirable or necessary to renew the network for instance in

10, 20 or 30 years. The timetable depends strongly on the owners’ desires, financing

arrangements and renovation resources. Figure 5.9 illustrates the first four years of the feeder

renovation scheme implemented by underground cabling on the example feeder. The renovation

is planned to be carried out in 20 years.

135

Figure 5.9. Example of a feeder renovation scheme; the first four years.

5.4. Impacts of implementation

Figure 5.10 depicts the development of reliability indices of the example feeder and the annual

investments required in the medium-voltage network. The background with diagonal lines

illustrates the first four years of renovation related to Figure 5.9.

0

50 000

100 000

150 000

200 000

250 000

300 000

350 000

400 000

450 000

500 000

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

Year

Inve

stm

ent [

€/a

]

0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

Cha

nge

in re

liabi

lity

indi

ces

Investment SAIFI SAIDI MAIFI

SAIDI

SAIFI

MAIFI

Cha

nge

in r

elia

bili

ty in

dice

s

100 %

Figure 5.10. Investments in the example feeder and the development of reliability indices as the renovation

proceeds.

136

Figure 5.10 shows that the effects of underground cabling on reliability indices are substantial;

SAIFI reduces by 72 % and SAIDI by 63 % in the case feeder. There are no autoreclosings at

all on the network at the end of the renovation schedule. Figure 5.11 depicts the effects of the

renovation scheme on maintenance, fault repair and outage costs; the outage costs decrease by

77 %.

0

5 000

10 000

15 000

20 000

25 000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

Year

Cos

ts [€

/a]

Outage costs

Maintenance

Fault repair

Figure 5.11. Development of costs occurring on the example feeder as the renovation proceeds.

The question of renovation schedule is strongly linked with the development of the

replacement and present value of the network, as well as the network components removed in

the renovation from the network before they reach their lifetime. Figure 5.12 shows how the

above renovation affects the replacement and present value of the network on the case feeder.

The figure shows that the replacement value of the medium-voltage network nearly doubles

when changing over to the underground cabling. Simultaneously, the network age is reduced

from the initial 30 years so that the present value of the network when approaching the end of

the renovation period is about 75 %. The figure also depicts the financial value of wood poles

removed from the network before the end of their lifetime, proportioned to the total network

length. The renovation has to be carried out for complete sections, and therefore, owing to the

age structure of the line, substantial amounts of network sections that still have some techno-

economical lifetime left may be removed from the network. For the example feeder, the value

of the removed feeder sections is on average 2 000 €/km. This is about 5 % when proportioned

to the total costs of underground cabling. The renovation schedule has a strong impact on the

value and amount of removal; if the renovation schedule is tight, the number of removed

network components with some lifetime left will increase. On the other hand, if the renovation

137

schedule can be extended, the amount of removed components can be minimised. In the plan

made for the example feeder, extending the renovation schedule to 30 years (Figure 5.13) will

significantly reduce the amount of annually removed pole assets that have some lifetime left,

the value of removal being less than 500 €/km. On the other hand, if the schedule can be

stretched, the amount of removals can be minimised. Halving the renovation period planned for

the example feeder to ten years doubled the amount of removals. In reality, this removal is not

necessarily shown in the financial performance of the distribution company, since the existing

network assets have probably been depreciated during the first 20–25 years. A typical lifetime

for an overhead medium-voltage line in rural areas is 40–50 years.

0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

8 000

9 000

10 000

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

Year

Lost

ass

et o

f woo

d po

les

[€/k

m]

0 %

20 %

40 %

60 %

80 %

100 %

120 %

140 %

160 %

180 %

200 %

Ne

t pre

sen

t an

d r

ep

lace

me

nt v

alu

e

Replacement value

Present value

Removed asset of wood poles Removed asset of wood poles [€/km]

Figure 5.12. Development of the replacement and present value of the example feeder and the amount of

pole assets having some lifetime left, proportioned to the total line length. Reinvestment schedule 20 a.

0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

8 000

9 000

10 000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Year

Lost

ass

et o

f w

ood

pole

s [€

/km

]

0 %

20 %

40 %

60 %

80 %

100 %

120 %

140 %

160 %

180 %

200 %

Net

pre

sent

and

rep

lace

men

t val

ue .

Replacement value

Present value

Removed asset of wood poles

Removed asset of wood poles [€/km]

Figure 5.13. Development of the replacement and present value of the example feeder and the amount of

pole assets having some lifetime left, proportioned to the total line length. Reinvestment schedule 30 a.

138

Deviating from the previous consideration presented in Figure 5.14 for a single feeder, the focus

is now on a larger network section covering the whole area of a primary substation. The

network section under consideration is ten times as large as in the case of an example feeder.

The figure shows, according to different investment schedules, what is the proportion of those

wood poles removed from the network that have reached their lifetime (in this case 40 years).

The amount of renovation is evenly distributed to different years according to the length of the

reference period so that at the end of the renovation program, the present overhead network is

fully replaced by underground cabling. The figure shows that with the shortest ten-year

investment schedule, in the first five years, the renovation can be targeted to poles that no

longer have present value. After the sixth year of the investment schedule, the proportion of

wood poles with some lifetime left in the renovated network sections increases significantly.

The percentage describes the proportion of “zero-years-old” equivalent poles having full

present value in the renovation. For instance, in the tenth year, about 65 % of the pole asset to

be renovated still has full present value. The proportion of these poles decreases significantly

when the renovation schedule is extended to 20 or 30 years. The consideration for the larger

network section, that is, the whole area of a primary substation, is based on a theoretical

analysis of the pole asset mass, in other words, there is no actual target-specific renovation plan

as in the case of the example feeder in Figure 5.9.

0 %

20 %

40 %

60 %

80 %

100 %

120 %

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

Year

Am

ou

nt o

f wo

od

po

les

wh

ich

ha

ve b

ee

n

rem

ove

d a

t fu

ll a

ge

fro

m th

e n

etw

ork

30 a schedule

20 a schedule

10 a schedule

Figure 5.14. Amount of wood poles having reached their lifetime at the moment of removal from the

network in the 10, 20 and 30 year renovation schedule.

139

In the strategy work, also the effects of the development alternative on the distribution fees are

of interest. The analysis of these effects is based on the cost difference between a traditional

development solution and an alternative network technology. Based on the above example

network, the underground cabling strategy is compared with an alternative where an overhead

line is renovated to the roadside (in practice, a completely new line was built). In the example,

the renovation cost is here divided by the distributed energy on the average feeder (107

MWh/km). The renovation costs are calculated for a 20 year renovation schedule. The

renovation costs of cabling per energy transferred are 0.84 cent/kWh higher than in overhead

line alternative (Figure 5.15) in the example case. If the OPEX benefit is taken into account

(reduction in maintenance and fault repair costs), the renovation cost is 0.80 cent/kWh higher

than in overhead line alternative. The future target price level of underground cabling, derived

in the determination of the operating environment, has been used as the unit price of cabling in

the analysis of the example case.

Comparison: transfer of the cable to the roadside vs. transfer of the overhead line to the roadside

(0.80 cent/kWh with the OPEX benefit)

���� 0.84 cent/kWhCosts

Investments (cable) 1 946 255Investments (overhead line) 1 144 000Saving in customer outage cost (40 a) 291 330Maintenance (40 a) 100 918Fault repair (40 a) 9 925

Figure 5.15. Comparison of costs of different investment strategies and effects on the distribution fee.

The principle of the comparison method has a strong influence on the final costs of a strategy. If

in the example case, as an alternative to underground cabling, the old overhead line is renovated

in the existing line path in connection of pole renovation, the additional cost of cable renovation

per transferred energy would be 1.42 cent/kWh and 1.35 cent/kWh taking the OPEX into

account. In that case, it is assumed that the conductors and cross-arms can still be used on the

renovated line. The higher difference in costs is explained by the cost difference between a

completely new overhead line and pole renovation.

The above example shows that the network renovation schedule has a significant influence on

the costs. Considering the investment costs alone, pole renovation based on the lifetime of poles

would be the most beneficial option from the perspective of national economy. The benefits of

this alternative are further emphasised if the selection of renovation targets is based on the

140

different models developed in the recent years for pole ageing (Datla and Pandey, 2006),

(Hilber et al., 2005). Optimisation of the pole replacement schedule alone cannot provide an

answer to the challenges posed for instance by increasing labour costs, or the need to develop

network reliability. Development of the operating environment increasingly drives to such

network structural solutions that are immune to various weather events and that are cost-

efficient with respect to maintenance.

5.5. Conclusions on strategic decisions

There is a large variety of network technologies applicable to the strategy. The palette of

technologies available depends strongly on the boundary conditions set by the operating

environment and the objectives of the company owners. If the main target in the development

strategy is to make the network immune to environmental disturbances as soon as possible, the

outcome of the strategy from the viewpoint of technologies and the investment schedule is

different than if the target is only moderate renovation of the oldest network sections in order to

increase the present value of the network. The purpose of the example calculations and results

presented in this section is to illustrate how the methodology can actually be applied to the

strategic development of the network. Nevertheless, it is pointed out that the results cannot be

generalised as such, but each distribution network has to considered individually.

From the perspective of cost optimisation, the strong interactions between different

technologies have to be recognised and taken into account. The techno-economic feasibility of a

single network technology depends on whether the technology in question is used alone in

network development, or some other technologies are used in parallel in the process. Further,

the mutual order of investments in different technologies has an impact on the final result. For

instance, adoption of network automation before large-scale network renovation will reduce the

outage cost benefits of technologies applied later in the network. This is an issue that has to be

taken into account in the long-term network planning at the latest.

The strategy process has shown the importance of the operating environment in the electricity

distribution business. During this research work, the technology development and changes in

cost components in particular related to underground cabling technology have raised a question

141

of extensive underground cabling in rural areas. We may thus conclude that in the strategy

work, it is of paramount importance to reflect on the company targets with respect to the

general development in society and update the company strategies. In other words, strategy

work is an ongoing process. The owners’ objectives may eventually have a significant influence

on the investment strategy. The presence of owners directs the strategy work towards an

iterative, conversational process.

142

143

6. Conclusions

Over the past years, electricity distribution business has faced numerous challenges.

Simultaneously as the climate change and ageing networks have put pressure on developing the

distribution networks, the regulation of the distribution business has increased thereby

compelling the companies to improve the cost-efficiency of their operations. The growing

challenges have forced to find new and more efficient solutions in network development. To

this end, methodology has been developed to support strategic decision-making in electricity

distribution networks. The main contribution of this doctoral dissertation is in the analysis and

development of the strategy process of the long-term planning of electricity distribution

networks. The scientific contributions of the dissertation are the analysis and development of

the concept for strategy process, the calculation and analysis methodology developed into the

concept, and assurance of the functioning of the concept.

The concept of strategy process proposed in this doctoral dissertation can well be utilised in the

long-term development of electricity distribution networks. Furthermore, this is the first time

that strategy-level network planning methodology is presented as extensively and as a single

entity for rural distribution networks. The results of this work can be considered internationally

applicable, yet it is emphasised that diverging regulatory models in different countries call for

specific, detailed methodology in each country. The concept introduced in this work facilitates

the distribution companies to recognise and prepare for factors that have an impact on the

strategic development of distribution networks. The methodology presented in the dissertation

assists in discerning how various changes in the operating environment may affect the

investment decisions.

The most essential findings of the doctoral dissertation are concretised in the following:

- The planning concept and methods for strategic planning presented in this work (which

take into account the network age, reliability, electrotechnical and mechanical condition of

the network and environmental factors) are applicable to practice.

- The need for strategic planning has increased for instance as a result of more focused

owner policy and intensified economic regulation. Success in the distribution business

144

calls for an ability to anticipate and react to changes in the operating environment.

Electricity distribution network business, similarly as any business or investment target,

should be profitable. The most profitable solutions that best serve the owners interests can

be found when there is comprehensive knowledge on the business in the field, and the role

of the strategy process in decision-making is understood in full.

- There is no single universal model to be applied to strategic decision-making, but each

development task has to be carried out case by case. This is due to the different operating

environments and diverging targets set by the owners of the distribution companies;

moreover, these are issues that have a strong influence on the outlines and progress of the

strategy process.

- All the essential information on the distribution network (e.g. reliability, age and condition

data, information on the electrotechnical state of the network) and information on the

operating environment of the business have to be available for the strategic planning.

Should all these necessary data be not at hand for decision-making, the best results may

not be reached in minimisation of the total costs. The importance of analysing several

information sources simultaneously was accentuated for instance in section 5.3. However,

it is the strategy process that determines which of the network renovation criteria is the

most decisive one in the distribution company in question.

- The strategy process has to be updated from time to time. For instance, the entry of

electric vehicles into the market may have an influence on distribution network design in

the future. Moreover, the changing and evolving objectives and requirements of society

together with the general technological development necessitate up-to-date information in

strategic decision-making.

- Outage costs constitute an important part of the economic regulation of the electricity

distribution business, and reliability is a key driver in network planning. This results from

the constant development of society and intensified requirements for reliable supply of

electricity associated with it. The significant role of outage costs is discussed for instance

in sections 3.2 and 3.3.

145

- The high average age of distribution networks and the high renovation needs in the near

future constitute a challenge but also an opportunity. In Finland, electrification of rural

areas took place almost simultaneously in most parts of the country, and consequently, the

renovation needs are not restricted to single distribution companies. Large-scale

renovation needs, on the other hand, enable cost-efficient adoption of new network

structures and construction methods (large-scale transfer of overhead lines to roadsides

and underground cabling serving as examples).

Based on the strategy analyses and analyses on the operating environment, we may conclude

that under the conditions prevailing in Finland, in the network development work, even large

network-technological changes could be considered in the distribution system. This conclusion

is supported by the experiences obtained from the actual distribution companies during the

strategy process.

The changes taking place both in the operating environment and network technologies call for

further development of the strategy process proposed in this doctoral dissertation. Among

others, the role of distributed generation and smart grids in the network development will grow.

In order to be able to reliably embed such significant topics in the strategy process, intensive

research on these topics is required in the future also. To a certain degree, these issues will be

addressed in various national and international research projects already launched on the theme.

146

147

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