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lEI P0WEk AN0 ENEk0 5EklE5 44

Series Editors: Professor A.T. !ohns

Professor D.F. Warne
Economic Evaluation of
Projects in the Electricity
Supply Industry
0tber volumes in tbis series:
volume 1 Power circuit breaker tbeory and design C.H. Flurscheim (Editor)
volume 4 lndustrial microwave beating A.C. Metaxas and R.!. Meredith
volume 7 lnsulators for bigb voltages !.S.T. Looms
volume 8 Variable freguency AC motor drive systems D. Finney
volume 10 5F6 switcbgear H.M. Ryan and C.R. !ones
volume 11 Conduction and induction beating E.!. Davies
volume 13 5tatistical tecbnigues for bigb voltage engineering W. Hauschild and
W. Mosch
volume 14 Uninterrugtable gower sugglies !. Platts and !.D. St Aubyn (Editors)
volume 15 0igital grotection for gower systems A.T. !ohns and S.K. Salman
volume 16 Electricity economics and glanning T.W. errie
volume 18 Vacuum switcbgear A. Creenwood
volume 19 Electrical safety: a guide to causes and grevention of bazards
!. Maxwell Adams
volume 21 Electricity distribution network design, 2nd edition E. Lakervi and
E.!. Holmes
volume 22 Articial intelligence tecbnigues in gower systems K. Warwick, A.C. Ekwue
and R. Aggarwal (Editors)
volume 24 Power system commissioning and maintenance gractice K. Harker
volume 25 Engineers' bandbook of industrial microwave beating R.!. Meredith
volume 26 5mall electric motors H. Moczala
volume 27 AC-0C gower system analysis !. Arrill and .C. Smith
volume 29 Higb voltage direct current transmission, 2nd edition !. Arrillaga
volume 30 Flexible AC Iransmission 5ystems {FACI5) Y-H. Song (Editor)
volume 31 Embedded generation N. !enkins
volume 32 Higb voltage engineering and testing, 2nd edition H.M. Ryan (Editor)
volume 33 0vervoltage grotection of low-voltage systems, revised edition P. Hasse
volume 34 Ibe ligbtning asb v. Cooray
volume 35 Control tecbnigues drives and controls bandbook W. Drury (Editor)
volume 36 Voltage guality in electrical gower systems !. Schlabbach
volume 37 Electrical steels for rotating macbines P. eckley
volume 38 Ibe electric car: develogment and future of battery, bybrid and fuel-cell
cars M. Westbrook
volume 39 Power systems electromagnetic transients simulation !. Arrillaga and
N. Watson
volume 40 Advances in bigb voltage engineering M. Haddad and D. Warne
volume 41 Electrical ogeration of electrostatic grecigitators K. Parker
volume 43 Ibermal gower glant simulation and control D. Flynn
volume 44 Economic evaluation of grojects in tbe electricity suggly industry H. Khatib
volume 45 Progulsion systems for bybrid vebicles !. Miller
volume 46 0istribution switcbgear S. Stewart
volume 47 Protection of electricity distribution networks, 2nd edition !. Cers and
E. Holmes
volume 48 Wood gole overbead lines . Wareing
volume 49 Electric fuses, 3rd edition A. Wright and C. Newbery
volume 50 Wind gower integration: connection and system ogerational asgects . Fox
volume 51 5bort circuit currents !. Schlabbach
volume 52 Nuclear gower !. Wood
volume 53 Condition assessment of bigb voltage insulation in gower system
eguigment R.E. !ames and . Su
volume 55 Local energy: distributed generation of beat and gower !. Wood
volume 56 Condition monitoring of rotating electrical macbines P. Tavner, L. Ran,
!. Penman and H. Sedding
volume 905 Power system grotection, 4 volumes
Economic Evaluation of
Projects in the Electricity
Supply Industry
Hisham Khatib
The Institution of Engineering and Technology
Published by The Institution of Engineering and Technology, London, United Kingdom
1996, 2003 The Institution of Electrical Engineers
New cover 2008 The Institution of Engineering and Technology
First published 1996 (0 85296 908 2)
Revised edition 2003 (0 86341 304 8)
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8ritisb Library Cataloguing in Publication 0ata
Khatib, Hisham, 1936 -
Economic evaluation of projects in the electricity supply industry. -
New ed. - (IET Power and energy series no. 44)
1. Electric utilities - Finance - Evaluation
2. Electric utilities - Economic aspects - Evaluation
I. Title II. Institution of Electrical Engineers
l58N {10 digit) 0 86341 304 8
l58N {13 digit) 978-0-86341-304-9
Typeset in India by Newgen Imaging Systems (P) Ltd, Chennai
First printed in the UK by MPC ooks Ltd, odmin, Cornwall
Reprinted in the UK by Lightning Source UK Ltd, Milton Keynes
Preface xi
Acknowledgements xv
1 Global electrical power planning, investments and projects 1
1.1 The value of electricity 1
1.2 Integrated resource planning 2
1.3 The changing electrical power industry scene 3
1.3.1 Reform trends in the electricity supply industry 4
1.3.2 Environmental concerns and the efciency of
generating plant 5
1.3.3 Environmental concerns and the growing
importance of natural gas 6
1.3.4 Rehabilitating, retrotting and repowering of
existing power facilities 7
1.3.5 The growing importance of demand side
management (DSM) 9
1.4 The global electrical power scene 9
1.4.1 Electricity and the global energy scene 10
1.4.2 Electricity and the world economy 10
1.5 Considerations that will inuence future investments in
electricity generation 12
1.5.1 Future electricity generation technologies 12
1.5.2 Future electricity generation fuels 13
1.6 Projects and capital investments 14
1.6.1 Generation investment and projects 14
1.6.2 Transmission and distribution projects 15
1.6.3 Sources of investment funds 16
1.7 Epilogue 17
1.8 References 18
vi Contents
2 Considerations in project evaluation 21
2.1 Project selection and evaluation 21
2.2 Project development 22
2.2.1 The pre-investment stage 22
2.2.2 The investment phase 26
2.2.3 The operational phase 27
2.2.4 Post-operation evaluation 27
2.3 Other considerations in project evaluation 28
2.4 References 30
3 Time value of money (discounting) 31
3.1 Discounting 31
3.2 Discounted cash ows 33
3.3 Net present value (NPV) 34
3.4 Accounting for ination in cash ows 35
3.5 Considerations in present valuing 37
3.5.1 Future and past valuing 37
3.5.2 Annuity factor 38
3.5.3 Capital recovery factor (CRF) or equivalent
annual cost 39
3.5.4 Grouping monthly and hourly ows 41
3.6 References 41
4 Choice of the discount rate 43
4.1 Introduction 43
4.2 The discount rate 44
4.3 Calculating the discount rate 45
4.3.1 Government nanced projects 46
4.3.2 Business investment projects 46
4.4 Controlling the value of the discount rate 52
4.4.1 Capital structuring 52
4.4.2 Transferring risk 53
4.5 Other forms of the discount rate 53
4.5.1 Weighted-average cost of capital 53
4.5.2 Utilisation of multiple discount rates 54
4.6 Summary 54
4.7 References 55
5 Financial evaluation of projects 57
5.1 Introduction 57
5.1.1 Evaluation of costs and benets 57
5.1.2 Project nancial costs 58
5.1.3 Financial benets of the project 59
Contents vii
5.2 Least-cost solution 59
5.2.1 Present value method 60
5.2.2 Annual cost method (equivalent uniform
annual cost method) 62
5.3 Measuring worth of the investment 65
5.3.1 Internal rate of return 65
5.3.2 Net present value (NPV) 67
5.3.3 Benet/cost ratio 67
5.3.4 Other non-discount criteria for evaluation 68
5.3.5 Payback period 68
5.3.6 Prot/investment ratio 68
5.4 Owners evaluation of protability commercial
annual rate of return 69
5.5 References 69
6 Considerations in project evaluation 71
6.1 Base cost estimate and contingencies 71
6.1.1 Physical contingency 71
6.1.2 Price contingency 72
6.2 Interest during construction 73
6.3 Sunk costs 74
6.4 Depreciation and interest charges 74
6.5 Financial projections 75
6.5.1 Financial performance and nancial statements 76
6.5.2 Financial ratios 78
6.5.3 Flow of the funds statement sources and
applications of funds 80
6.6 Evaluation of benets in the electricity supply industry 81
6.7 Timing of projects 82
6.8 Dealing with projects with different lives and
construction periods 82
6.9 Expansion projects 83
6.10 System linkages 83
6.11 References 85
7 Economic evaluation of projects 87
7.1 Introduction 87
7.2 From nancial evaluation to economic evaluation 89
7.3 Transfer payments 89
7.4 Externalities 90
7.5 Border and shadow pricing 91
7.5.1 Pricing traded inputs and outputs 92
7.5.2 Pricing non-traded inputs and services 93
7.6 References 95
viii Contents
8 Environmental considerations and cost estimation in
project evaluation 97
8.1 Introduction 97
8.2 Environmental impacts of electricity fuels 99
8.2.1 Environmental impact of different generation fuels 101
8.3 Environmental evaluation 102
8.4 Environmental impacts and the discount rate 102
8.5 Health and environmental effects of electricity 103
8.5.1 Direct health effects 103
8.5.2 Environmental impact 104
8.6 Investment costs in reducing dangers to health and
environmental impacts 106
8.7 Evaluation of the environmental cost of electricity generation 107
8.7.1 Assessing health impacts and costs 107
8.7.2 Assessing damage to buildings, properties and
forests by air pollution 107
8.7.3 Climate change costing 109
8.8 References 111
9 Electricity generation in a carbon-constrained world 113
9.1 Introduction 113
9.2 Climate conventions and Kyoto 114
9.2.1 Case Study: the Kyoto Protocol and the Marrakech
declaration and accords 115
9.3 Electricity generation and climatic change agreements 116
9.3.1 Flexible project mechanisms 117
9.3.2 Emissions trading 118
9.3.3 Encouraging emissions reductions 120
9.4 Introduction to low emissions and emissions-free
power generation 120
9.4.1 Generation cost of power sources 121
9.5 Clean fossil-fuel-based power technology 121
9.6 Prospects for non-fossil-fuel power generation 124
9.6.1 Prospects for nuclear energy 124
9.6.2 Prospects for wind power 124
9.6.3 Prospects for solar cells 125
9.6.4 The virtual power plant 126
9.7 References 126
10 Economics of reliability of the power supply 129
10.1 Introduction 129
10.2 The value of reliability 131
10.3 Reliability in system planning 132
10.3.1 Empirical planning rules 132
Contents ix
10.3.2 Supply design standards 133
10.3.3 Costbenet analysis 133
10.4 Detailed nancial and economic evaluation 134
10.4.1 System adequacy and economics 134
10.4.2 Assessment and economics of generation adequacy 135
10.5 Financial and economic evaluation of quality of
electrical power 138
10.6 Evaluation of investment in generation 139
10.6.1 Valuing cost of interruptions 140
10.6.2 Incorporating reliability worth in
generation planning 141
10.7 References 144
11 Electricity trading 145
11.1 Introduction 145
11.2 Electricity trading worldwide 146
11.2.1 Electricity trading in the US 147
11.2.2 UK electricity market trading 148
11.2.3 The Nordic market 150
11.2.4 The California market 150
11.2.5 Electricity markets across Europe and elsewhere 152
11.3 Electricity traders 153
11.3.1 Case study: sample of services offered by
power marketers (traders) 155
11.4 Future strategies and growth 156
11.5 References 157
12 Evolvement of the electricity sector utility for the future 159
12.1 Introduction 159
12.1.1 Phase I: early 20th century private sector investment
and monopolistic market behaviour 159
12.1.2 Phase II: mid-20th century public sector intervention
and inefciency 159
12.1.3 Phase III: late-20th century unbundling, competition,
regulation and privatisation 160
12.1.4 Phase IV: recent developments industry convergence
and globalisation 160
12.2 Reorganising the ESI 160
12.2.1 The opportunities presented by liberalisation 162
12.3 Barriers in liberalised markets 164
12.4 Electricity and the new digital economy 164
12.5 The utility of the future 166
12.6 The virtual utility of the future 167
12.7 DSM programmes in deregulated markets 167
x Contents
12.8 The need for a regulator 169
12.9 References 170
13 Project analysis: evaluation of risk and uncertainty 171
13.1 Introduction 171
13.2 Project risks 171
13.3 Sensitivity analysis 174
13.4 Break-even point analysis 176
13.5 Decision analysis 177
13.6 Risk analysis (the Monte Carlo simulation) 178
13.7 Consideration in risk analysis 182
13.7.1 Building up probability distributions 182
13.7.2 Disaggregation 183
13.7.3 Correlation 183
13.7.4 Effect on the discount rate 184
13.8 The value of risk management in liberalised markets 184
13.9 References 185
14 Risk management in electricity markets 187
14.1 Introduction 187
14.2 Qualifying and managing risk 187
14.2.1 Forward contracts 189
14.2.2 Futures contract 189
14.2.3 Options 190
14.2.4 Swaps 191
14.2.5 Political risk 192
14.3 Decision making 192
14.3.1 The decision-making process 193
14.4 References 194
Appendix1 Financial evaluation for choice of transformer 195
Appendix2 Glossary 201
Index 209
The rst editionof this bookappearedin1997, it is nowmore thanve years since then.
During that time signicant developments (technological as well as managerial) have
taken place in the electricity supply industry (ESI) in Europe as well as in many coun-
tries in the world. Signicant strides in technology and efciency of power generation
have materialised during the past few years as well as advancement in information
and telecommunications, which has helped to promote electricity markets and trade.
There is a global trend towards liberalisation and privatisation of the electricity
supply industry. This is coupled with growing environmental awareness and increas-
ing prospects for ratication of the Kyoto Protocol. All have dramatically affected the
ESI worldwide. Developments that have taken place during the past decade outweight
all that has taken place since the middle of the 20th century.
This necessitated a review and a new edition of this work to take into account
these developments that affect the way projects are conceived and evaluated by
the industry. With the gradual demise of government-owned utilities, nancial and
economical evaluation of projects is gaining more importance in competitive and
liberalised markets, as is risk management.
Financial and economic evaluation of projects is usually carried out by a team
of engineers, economists and nancial analysts. In the case of economic evaluation
of large projects, there is an involvement of economic and environment disciplines,
and the undertaking of an analysis that is beyond the prociency of most engineers,
accountants and nancial analysts. Projects in the electricity supply industry are
slightly more sophisticated than other investment projects in the industrial sector
and more capital intensive. It is not easy to introduce people from other disciplines
(economists, accountants, nancial analysts) into the intricacies of electrical engi-
neering; however, their role remains very important in the evaluation of projects in
the power industry. It may be easier to acquaint engineers with the fundamentals of
nancial and economic evaluation of projects. This will allow for an easier dialogue
between different disciplines in any project evaluation team, and correspondingly
lead to better results.
This book is written primarily for engineers to assist them in project evalua-
tion; therefore the treatment assumes some understanding of engineering, particularly
the electrical power technology and utilisation of computers for simulation. All the
xii Preface
nancial and economic analyses and examples are brief and simplied to allowfor the
quick grasp of ideas and understanding of the subject by the non-specialist. However,
the book is also useful to economists and nancial analysts in understanding issues
encountered in engineering projects and the electricity supply industry and the means
of evaluating their economic implications. Chapters 1, 812 and 14 are, in particular,
power engineering biased.
Simplied techniques for the nancial and economic evaluation of projects are not
difcult to understand by power engineers with their engineering and mathematical
knowledge. There are plenty of simple evaluation rules that have to be grasped by
engineers and which will give them a good insight to simple nancial analysis and
economic evaluation that will sharpen their understanding of the economic implica-
tions of investments and allow them to understand concepts such as the time value of
money, discounting and the discount rate, rate of return and risk evaluation. Such con-
cepts are essential knowledge for power system planners and others who are involved
in project selection and strategies.
The book is mainly concerned with the nancial and economic evaluation of
projects. Therefore it does not dwell on the other related aspects of demand prediction,
technology, management and the framework of the power sector planning. These are,
of course, very important for nancial and economic evaluation; however, they are
treated in detail in the available literature, and will be referred to when they are of
direct bearing on evaluation. Also this book does not dwell on nancial projections
of a commercial nature. Therefore the book is mainly concerned with the evaluation
of projects, particularly capital-intensive projects like those of the electricity supply
industry. Most of the investments carried out by utilities and investors are in the form
of individual projects. The evaluation is required to nd out the least-cost solution as
well as the rate of return on the investment. The whole performance of the investor, as
a complex commercial entity, can be assessed through nancial ratios and pro forma
nancial statements. These are briey described in Chapter 6.
Many books have been written in the United States about engineering economics
and evaluation of projects, than have been written in the UK. Evaluation is not a
universal science; approaches and criteria for assessment differ in the UKand Europe
fromNorth American practices in some aspects. The differences are, however, limited
and some of them will be pointed out in the book.
International development agencies, particularly the World Bank, the Organisa-
tion for Economic Corporation and Development (OECD), different United Nations
agencies and other national and regional development funds signicantly contributed
towards understanding project evaluation, especially the economics of externalities,
shadow pricing and environmental damage costing aspects. This book draws on their
work wherever relevant.
This second edition is signicantly enlarged compared with the rst edition. There
are three major signicant additions. The rst concerns environmental considerations
and prospects for emissions trading in a carbon constrained world (Chapters 8 and 9),
the other is electricity trading and nancial management of risk in growing liberalised
markets (Chapters 11and14) as well as the evolutionof the electricitysector andutility
Preface xiii
of the future (Chapter 12). The secondeditioncontains four additional chapters tocater
for these recent and possible future developments in the electricity supply industry.
This book will also be useful for post-graduate electrical power engineering
students preparing for a higher degree. It introduces them to the concepts of nan-
cial and economic evaluation and the criteria that govern investment in the electricity
supply industry.
This book covers a wide ground and could not be written without beneting from
the published effort of others as well as on a lot of literature; therefore every chapter
has a list of relevant references, upon which I have drawn, and that will enable the
interested reader to sharpen his knowledge about the subject.
The analysis in this book has greatly beneted from my extensive experience in
project evaluation which I gained while associated with the electricity supply industry
world wide as well as in Jordan, through my association with the World Electric-
ity Council and the Arab Fund for Economic and Social Development, a leading
regional development institution located in Kuwait. However, any omissions are my
I am particularly thankful to the management of the Arab Fund for supporting
this work.
Chapter 1
Global electrical power planning,
investments and projects
1.1 The value of electricity
Electricity is versatile, clean to use, easy to distribute and supreme to control. Just
as important, it is now established that electricity has better productivity in many
applications than most other energy forms [1]. All this led to the wider utilisation of
electricity and its replacement of other forms of energy in many uses. Demand for
electricity is now growing globally at a rate higher than that of economic growth and,
in many countries, at almost 1.52 times that of demand for primary energy sources.
With the type of technologies and applications that already exist, there is nothing to
stop electricitys advancement and it assuming a higher share of the energy market.
Saturation of electricity use is not yet in sight, even in advanced economies where
electricity production claims more than half of the primary energy use. Other than
for the transport sector, electricity can satisfy most human energy requirements. It is
expected that, by the middle of the 21st century, almost 70 per cent of energy needs
in some industrialised countries will be satised by electricity [2].
Electricity has become an important ingredient in human life; it is essential for
modern living and business. Its interruption can incur major losses and create havoc in
major cities and urban centres. Its disruption, even if transient, may cause tremendous
Therefore, continuity of electricity supply is essential. Also, with the widespread
use of computers and other voltage- and frequency-sensitive electronic equipment,
the importance of the quality of supply has become evident. A signicant propor-
tion of investment, in the electricity supply industry (ESI), goes into the reserve
generating plant, standby equipment and other redundant facilities needed to ensure
the continuity and high quality of the supply. Economics of reliability in the elec-
tricity supply industry is a very important topic [3], which will be dealt with in
detail in Chapter 10. Optimisation of investment in the ESI requires understanding of
markets, prediction of future demand and an approach based on integrated resource
2 Economic evaluation of projects in the electricity supply industry
1.2 Integrated resource planning
Integrated resource planning (IRP) seeks to identify the mix of resources that can best
meet the future electricity-service needs of consumers, the economy and society. It
is the preferred planning process for electric utilities. Under IRP different resource
options (incorporating investment and operational costs) are compared using a dis-
counting process and electrical power is visualised as a sub-sector of the energy
sector. In turn, the energy sector is one among many other sectors (agriculture,
health, education, transport, etc.) that make up the national economy. However,
energy and electricity permeate the whole economy; electricity linkage with all other
sectors and the national economy at large is stronger than any other sector. Energy is
also a capital-intensive activity that claims nancial resources and investments more
than other sectors, particularly if the country has no sufcient indigenous energy
resources [4].
The electricity sub-sector is usually the largest within the energy sector. It claims
more than one half of the total capital investment in the energy sector and, on average,
consumes almost one third of the countrys total fuel consumption (ratios vary from
one country to another). Capital investments in the electricity sector of developing
countries amounted to almost 9 per cent of their gross capital formation (total capital
investment) in the past two decades. This ratio is increasing owing to the rapid growth
of electricity demand in DCs [5]. Besides its direct linkages to almost all other sectors
of the national economy, the electricity sub-sector also has important environmental
impacts of a national, regional and global nature.
Investments in the electricity sub-sector are prompted by the requirements of the
economic and social sectors and by demography. However, their extent is restricted
by the countrys nancial and capital investment capabilities and the availability of
other energy sources, as well as the continuous improvement in efciency of util-
isation. The form and location of electricity production facilities and fuels utilised
are being increasingly inuenced by environmental considerations. Within the elec-
tricity sub-sector itself, limited nancial resources have to be optimally distributed
between generation extension and network strengthening, between urban and rural
areas and between different geographic locations. Electrical power production also
has to utilise different types of fuel and other resources depending on their local
availability, cost, and environmental impact. All this calls for integrated electricity
planning in a hierarchical manner (see Figure 1.1).
Integrated resource planning in electric power utilities also involves links with
the labour, capital and energy markets. It aims at ensuring that the policies (pricing
and accessibility to supply) and practices (quality and availability of supply) of the
power utilities adequately serve the purposes of the national economy. These purposes
include the availability of a reliable supply at the least possible cost, while efciently
utilising resources and protecting the environment.
Electricity is a secondary formof energy. It is produced, in most cases, by convert-
ing primary energy into heat that drives turbine-generators, or internal combustion
engine-generators. It is also produced directly by hydro-power driving hydro-turbines.
Therefore, electricity is an integral part of the energy scene. Fuels for producing
Global electrical power planning, investments and projects 3
Country A Country B Country C - - - - - Country N
Energy sector
Gas Oil Electricity Wood Other
Supply Demand


Global level
Intermediate level
Micro level
Energy sector
Investment planning
Loss of optimisation
Reliability of optimisation
Sub-sector planning
and management
Macro level
Pricing policy
Physical control
Technical methods
Education and information
Interaction between
energy sector and
rest of economy
Energy sub-sector
Energy demand
National objectives
and constraints
Transport Industry Energy Agriculture Other
Figure 1.1 Integrated resource planning in the ESI
Integrated resource planning in the ESI seeks to identify the mix of
resources that can best meet the future electricityservice needs of con-
sumers, the economy and society. It is presented in the hierarchical
framework shown here. Energy is one of the national economys most
extensive sectors and it permeates the whole economy and has link-
ages practically to all sectors of the economy. Environmental aspects
are increasingly linking the electricity sector to the energy sector and
through it to the national microeconomy and global environmental
Source: IAEA, References [6] and [7].
electricity are the main part of the primary fuels that constitute the Total Primary
Energy Requirements (TPER) in any country. Also, electricity can substitute other
fuels within the energy sector. Any study into integrated resources management in
the electricity sub-sector must consider this relationship. The aim is to have clean
production and efcient resources utilisation in the electricity sub-sector. This will
not only help to reduce the burden of energy on the national economy, but will also
allowefcient and clean replacement of other fuels, thus greatly enhancing integrated
resource management within the entire energy sector.
1.3 The changing electrical power industry scene
The electricity supply industry worldwide has resisted rapid change. This is mainly
because of the inertia of its large size and investments, and being monopolistic in
4 Economic evaluation of projects in the electricity supply industry
most cases. Until recently, change has been slow technologically and managerially.
Beside the widespread utilisation of semi-conductors and electronics in almost every
electrical power facility, technological change has been gradual. Most electricity
utilities continued to be monopolies with, in most cases, government ownership and
The oil crises of the 1970s shocked the industry and shifted emphasis from
expansion into conservation and efciency. From the late 1980s and 1990s onwards
tremendous developments in the management, ownership, and control of the ESI
began to take place. These changes were prompted by three important factors.
The inuence of market economies, and its emphasis on competition, which lead
to restructuring and deregulation, liberalisation, private sector investment and
ownership as well as electricity trade. These developments were made possible
by the recent spectacular technological advancement in information technology
and communications.
Rapid changes in technology have occurred in both the generation of electricity
and in computing systems used to meter and dispatch power [8].
Growing environmental concerns that are prompting efciency, conservation
and conversion into cleaner fuels as well as emission-free renewable and distri-
buted generation. Such environmental concerns have advanced international
agreements and protocols, the most important of which is the Kyoto Protocol,
which will have lasting effects on the future of the ESI [9] (see Chapter 8).
These three factors, which were practically introduced in the last few years and are
still gaining momentum, have caused tremendous changes in the ESI. The structural
change and technological development that have taken place in the industry in the
past ten years outweigh developments since the middle of the 20th century.
The market economy also has led to greater emphasis on the efciency of invest-
ment and protability of capital. It has encouraged competition, the partnership of
the private sector and independent power producers in the industry. Environmental
concern encouraged more efcient electricity production, reduction of losses, utili-
sation of cleaner fuels, abatement of emissions, and control of pollution. In addition,
it greatly affected the fortunes of nuclear power. Emphasis shifted from growth into
demand management, from more sales into rationalisation of demand, containment
of emissions, and better consumer services.
These recent developments are analysed below in greater detail because of
their great relevance to the nancial and economical evaluation of electrical power
1.3.1 Reform trends in the electricity supply industry
Energy markets worldwide are currently in the midst of a fundamental transforma-
tion [10], as a result of technological change and policy reforms. The objectives
of these reforms are: to enhance efciency, to lower costs, to increase customer
choice, to mobilise private investment, and to consolidate public nances. The
Global electrical power planning, investments and projects 5
mutually reinforcing policy instruments to achieve these objectives are the intro-
duction of competition (often supported by regulation) and the introduction of private
participation. As a large number of developed and developing countries have success-
fully restructured their electricity and gas markets, an international best practice for
the design of the legal, regulatory, and institutional sector framework has emerged.
It includes [8]:
the corporatisation and restructuring of state-owned energy utilities;
the separation of regulatory and operational functions, the creation of a coher-
ent regulatory framework, and the establishment of an independent regulator to
protect consumer interests and promote competition;
the vertical unbundling of the electricity industry into generation, transmission,
distribution, and trade;
the introduction of competition in generation and trade and the regulation of
monopolistic activities in transmission and distribution;
the promotion of private participation in investment and management through
privatisation, concessions, and new entry; and
the reduction of subsidies and tariff-rebalancing in order to bring prices in line
with costs and to reduce market distortions.
These trends greatly widened the scope for nancial management in the ESI, intro-
ducing to the industry new nancial services like risk analysis and risk mitigation,
electronic trading, etc. (see Chapters 11 and 12).
1.3.2 Environmental concerns and the efciency of generating plant
Recently, there has been growing environmental concern about the role of energy,
particularly electricity production, in causing emissions that have local, regional and
possibly global effects, with long-term detrimental implications. This has prompted
emphasis on efciency as a very important way of curbing emissions.
Electricity generation is an inefcient conversion process. The bulk of the exist-
ing inventory of generating plant, globally, has a gross generation efciency of less
than 33 per cent. Vintage coal ring power stations have an efciency that averages
25 per cent. Signicant improvements in efciency have been achieved during recent
years, almost to the extent of 0.2 per cent points per annum. Gross global generation
efciency, over 33 per cent now, was estimated to be around 31 per cent in the 1980s,
29 per cent in the 1970s and as low as 27 per cent in the 1960s (Figure 1.2).
Modern, large and efcient thermal generating facilities utilising pulverised coal
have an efciency approximating 4344 per cent. Modern combined cycle gas tur-
bine (CCGT) plants claim an efciency nearing 60 per cent, and in the relatively few
instances of combined heat and power (CHP) arrangements, efciencies of fuel utili-
sation can exceed 80 per cent. However, owing to the very large inventory of existing
inefcient generating facilities worldwide, the average efciency of electricity gen-
eration will not signicantly improve in the short term. When the system losses of
10 per cent in industrialised countries, and more than 25 per cent in many developing
countries, are taken into account, the amount of energy reaching consumers in the
6 Economic evaluation of projects in the electricity supply industry
1900 1920 1940 1960 1980 2000

Figure 1.2 Development of electricity generation efciency in thermal plants
utilising pulverised coal [11]
form of electricity is less than 30 per cent of the caloric value of the fuel infeed. In
some developing countries it may be even lower than 20 per cent.
1.3.3 Environmental concerns and the growing
importance of natural gas
The growing importance of natural gas (also liqueed natural gas, LNG) as a source
of energy, particularly for electricity production, has enhanced the utilisation and
development of the gas turbine and its derivative (the high-efciency combined cycle
plant) at the expense of the capital-intensive traditional steam power stations.
Natural gas was a premiumfuel in the past. Recently, however, owing to its rapidly
increasing reserves, abundance, relative cheapness and cleanliness, it has become
the fuel of choice for electric power generation, whenever available. Environmental
considerations have played a considerable part in this regard. Compared with other
fuels, natural gas is a benign fuel. It has practically no sulphur, correspondingly
no sulphur dioxide (SO
), and it emits no particulate matter (PM). Its emissions of
carbon dioxide (CO
), which is the main greenhouse gas, and nitrogen oxide (NO
are almost half those of coal. This is detailed in Table 1.1.
Increasingly, more global natural gas production is used for electricity generation.
Utilisation of natural gas and LNG for power generation will gradually grow more
than that of any other fuel. However, its usage will continue to be limited by its
availability in only a few countries, its high cost of transmission through pipes, the
need for long-term contracts and the high cost of LNG. Only one fth of the present
production of natural gas is traded internationally. Natural gas projects cost more than
twice the amount of crude oil projects. Its transport may be six times as expensive.
All these factors are slowing the development and utilisation of natural gas as the
ideal fuel for electricity production.
Global electrical power planning, investments and projects 7
Table 1.1 Emissions from fossil fuels [12]
Fuel Air pollution emission (million tons/m.t.o.e. of fuel)
Coal (3% S) 0.081 0.018 3.57 0.106
Coal (1% S) 0.027 0.018 3.57 0.096
Fuel oil (residual) 0.060 0.017 3.13 0.004
Fuel oil (distillate) 0.006 0.009 3.19 0.002
Natural gas 0.012 2.07
Note: m.t.o.e. = million tons of oil equivalent.
1.3.4 Rehabilitating, retrotting and repowering of
existing power facilities [13]
Stringent regulations (environmental and otherwise) and waylaying conditions, which
increased the cost of new facilities, led to frenzied attempts to rehabilitate, refurbish
and repower existing facilities. Shortages of capital also contributed towards extend-
ing the life and improved utilisation of existing sites. Difculty in licensing new
nuclear facilities led to extending the life of existing facilities to 50 years.
Repowering involves modication of an existing plant by changing the method
used to generate power. Repowering may modernise the power plant, increase its
efciency, lower operating costs and/or increase output. Evaluation of the economics
of repowering and retrotting existing sites needs more sophisticated evaluation than
other projects. This will be detailed in later chapters.
Markets, particularly the EU energy market, require environmentally compli-
ant and economically competitive plants. Some power plants in Central and East
Europe are generally ageing, not well maintained, have high pollution and low ef-
ciency. Their technology is outdated. Consumers are direct victims of this ageing
infrastructure as they pay a high cost for power.
The business options for an investor/owner of generation in the EUto meet the new
pollution limits include demolishing and rebuilding, retrotting with emission-control
equipment or repowering to make use of low-emission gas-red CCGT technologies.
Demolition and replacement with newefcient equipment requires high capital costs.
Retrotting appears to be a valid option because of the high EUmarket environmental
requirements. If new pollution-control equipment can be retrotted for a relatively
low cost and the plant is still reasonably competitive, then this option should be
considered. However, retrotting is limited to the installation of modern pollution
control devices in order to meet emission limits. It does not improve efciency or
reduce the cost of power production.
If the existing plant is not competitive, retrotting will not help, and repowering
may be a viable option. Repowering, that is making substantial changes to power
plants at the end of their useful economic or environmental life, improves efciency,
8 Economic evaluation of projects in the electricity supply industry
Typical new combined cycle
Repowered combined cycle
$10 500/kW
Comparative EPC costs
(1) Assumes no opportunity cost for repowered facilities.
(2) 540/kW saving can be assumed that it is directly attributable with avoided steam turbine
costs. Total savings of $70/kW may be due to reuse of existing cooling system, water
treatment, and other site facilities. Specific cost estimates may differ significantly from
these estimates.
(3) A 3 per cent gas escalation and 10 per cent discount rate is assumed.
Comparative present worth
10-year fuel costs
Comparative costs for new and repowered combined cycle
Figure 1.3 Economics of repowering generating plant [13]
decreases environmental emissions and reduces operating cost. If existing equipment
can be reused, such as the steamturbines, repowering may be cheaper than rebuilding.
Complete replacement of major systems such as boilers and turbines, conversion
to combined-cycle operation (through the addition of combustion turbines and heat
recovery equipment) or introduction of circulating uidised bed (CFB) boilers are
the options to be considered for ageing power plants to comply with the EU standard
(see Figure 1.3).
For repowering to be economically attractive, owners must look for repowering
returns equal to their expected returns on other options. Depending on the state of the
facility, income and investment vary and so do the returns:
if the existing facility is physically or economically forced out of service, as is
net operating income is zero;
if the facility is operable and capable of cycling duty and sales into a competitive
market, the as is income may be surprisingly high; and
if the facility requires extensive investment (retrot) for environmental compli-
ance, as is investment may be quite high.
The capital investment required to repower ageing plants is offset by the life
extension of the plant, the decrease in operations and maintenance costs (O&M)
and increased efciency and power generation. Repowering with natural gas turbines
can be cost effective compared with building a same size new combined-cycle unit,
because existing equipment may be re-used.
Global electrical power planning, investments and projects 9
1.3.5 The growing importance of demand side management (DSM)
Prompted by the high cost and shortage of capital, many power utilities have found
it cheaper and more protable to invest in demand side management (DSM) rather
than extending the supply and building new facilities [14].
DSM activities vary and involve the following.
Changing the shape of the daily and seasonal peak load curves (reducing peaks
and lling the load curve valley).
Introducing and encouraging the use of more efcient electric apparatus.
Reducing waste and overuse, through pricing, regulations, and educating the
consumers. Under this category falls reducing system loss.
Conservation: beyond eliminating overuse, conservation helps to manage and
reduce demand without affecting the quality of life.
Substitution: some electricity benets can be substituted more economically by
other means. For instance, passive solar design of buildings can signicantly
reduce demand for lighting, electric and water heating.
Methods of evaluation of the benets and economics of DSM projects are referred
to later.
Most of these considerations will have benecial effects on the electricity supply
industry. They can lead to cleaner and leaner production facilities, more rational and
efcient use as well as fostering competition that assists in optimising the use of
resources; thus lowering costs and giving greater benets to the consumer. Invest-
ment requirements will be rationalised and electricity costs can be reduced. All this,
however, is going to be gradual and will vary from one country to another. The ESI
is different to telecommunications. Energy systems, particularly electricity systems,
have huge inertia; they are highly capital intensive and live for a long time. They also
demand a lot of licenses and way leaving. This, of course, delays reaping the benecial
results of some of these recent developments. Such delays have also been assisted by
slow technological change in the way electricity was being produced, transmitted, or
distributed in the past. Newand renewable energy sources (other than hydro) have not
yet lived up to their earlier promise or our expectations. Such sources, which can be
mostly only utilised as electricity, will take a dramatic boost in the future, if the present
worries about global warming are reinforced by more substantive arguments or proof,
and once the Kyoto Protocol is ratied. However, liberalisation of the markets is cre-
ating a new potential for the power industry. Technological change will increasingly
affect the way electricity is being generated and distributed. Distributed generation,
fuel cells, the virtual power plant andsimilar technological innovationassistedbymar-
ket liberalisation are gradually, but surely, changing the power industry into a new
1.4 The global electrical power scene
Total global electrical power production in 2001 amounted to around 15 700 terawatt-
hours (TWh), with an average of 2600 kilowatt-hours (kWh) per capita per annum.
10 Economic evaluation of projects in the electricity supply industry
The global installed electric power facilities are very difcult to quantify exactly.
Estimates vary from 3430 GW [15] in 2000 to over 4200 GW [16], with the prospect
of the latter gure being more accurate. Most of the world electricity production,
57 per cent, was in OECD countries with an annual average of 8800 kWh per capita;
and another 10 per cent in East Europe and the former Soviet Union. Developing
countries, which account for more than three quarters of the worlds population,
utilised only 33 per cent of the global electricity production, with an annual average
of 1100 kWh per capita.
Thermal power, mostly utilising solid fuels, accounted for 64 per cent of global
electricity production. Hydro-produced power accounted for 18 per cent and nuclear
for 16 per cent. Total fuel utilised to produce this electricity amounted to around
37 per cent of the worlds primary commercial fuel use. Detailed statistics of elec-
trical power in the three economic groupings (OECD, East Europe and developing
countries), energy, input fuels used and types are shown in Table 1.2.
1.4.1 Electricity and the global energy scene
As previously explained, electricity is part of the energy sector and demand for elec-
tricity is part of the total demand for energy. However, because of its virtues and
cleanliness, electricity is gradually substituting other forms of energy and enhancing
its role in the global energy scene.
Global primary energy consumption in 2001 amounted to over 9800 m.t.o.e. Of
this amount, 8900m.t.o.e. were fromcommercial energysources (oil, gas, coal, hydro,
nuclear). Non-commercial energy (waste, fuel wood and other forms of biomass) is
difcult to estimate, and accounts for the remainder. Of this global energy consump-
tion around 3450 m.t.o.e. were utilised to produce electricity. This amounts to around
37 per cent of the total global commercial energy primary use. In 1950 and 1970
energy input to produce electricity amounted to 18 per cent and 29 per cent of the
total primary consumption, respectively [17]. The growing role of electricity in the
global energy scene will continue in the future, as previously discussed.
1.4.2 Electricity and the world economy
There has always been a tight coupling between energy use and economic growth.
Demand for electricity has always displayed good correlation with that of global
economic growth, as measured by gross national product (GNP) in purchasing power
parity dollars ($ppp). This strong coupling between electricity and economic growth is
clearly shown in Figure 1.4.
During the past 25 years, electricity growth averaged 4 per cent per annum, which
is a high rate of growth. In the future, electricity demand growth is expected to match
the growth of the world economy. This is expected to average around 2.53.5 per cent
annually during the next few years.
The International Energy Agency (IEA) and the International Atomic Energy
Agency (IAEA) estimate that global electricity production will increase at an annual
average rate of 2.73 per cent during the rst decade of the 21st century [19]. There-
fore it is expected that total electricity production in 2010 will amount to around
Global electrical power planning, investments and projects 11
Table 1.2 Global electricity statistics
Electricity % Energy (m.t.o.e.) Elec.
Global electricity balance (2001)
OECD 1020 2000 9000 8800 57 5000 1970 39
400 420 1600 4000 10 1070 420 39
DCs 4580 1160 5100 1100 33 3430 1060 31
World 6000 3580 15 700 2600 100 9500 3450 37
GW TWh % of electricity Input (m.t.o.e.)
Fuels for electricity generation
Nuclear 360 2500 16 650 18%
Hydro 830 2900 18 250 7%
Thermal: 2330 10 000 64 2560 72%
solids 1100 6100 39 1570 44%
oil 430 1350 9 290 8%
gas 800 2550 16 700 20%
Other 60 300 2 110 3%
Total 3580 15 700 3570
Nuclear (TWh) Hydro (TWh) Thermal and
other (TWh)
Total (TWh)
Sources of electricity generation (2001)
OECD 2000 1300 5700 9000
East Europe 240 290 1070 1600
DCs 60 1310 3730 5100
World 2500 2900 10 300 15 700
Source: IAEA: Energy, Electricity and Nuclear Power Estimates for the period up to
2020 (July 2001).
IEA: World Energy Outlook (2000).
(1) Generation refers to gross generation.
(2) Capacity refers to net capacity.
(3) Fuel required for production of electricity is estimated at 255 g of oil equivalent per kWh for high
income and 270 g kWh
for East Europe and developing countries.
(4) Fuel equivalent of hydro generation is equal to the energy content of the electricity generated.
(5) m.t.o.e. = million tons of oil equivalent.
(6) Terawatt-hour (TWh) = 1000 million kWh, Gigawatt (GW) = million kW.
(7) Global electricity gures are not well documented. The above is a collection of data frommany sources
with some rounding approximations and estimation.
12 Economic evaluation of projects in the electricity supply industry
GDP (trillion $ 1990 expressed in purchasing power parity)

Figure 1.4 Electricity demand as a function of world GNP (excluding former
CPEs) [18]
20 000 TWh and in 2020 to 25 880 TWh. Most of this growth is going to occur in
developing countries, particularly in south-east Asia, a region that is enjoying a
rapid economic growth. In 2030 global electricity production is expected to exceed
28 000 TWh. Half of this amount will be accounted for by developing countries [20].
1.5 Considerations that will inuence future investments
in electricity generation
Environmental considerations [20] will greatly continue to inuence the generating
system through choice of technology and fuels, particularly if there is future carbon
taxation. Electricity generation is highly capital intensive and the inertia of existing
generationsystems is considerable. Existingsystems involvedhuge amounts of capital
investment, which every electricity producer is eager to use to the end of its useful
life. Because of the huge stock of current generating systems, technological change
will be very gradual. Choice of fuels will also be restricted by: the existing stock of
plants, national fuel endowments (particularly in the case of coal), capital and human
resources (in case of nuclear), development of natural gas networks and its future
price, and availability and cost of alternative resources. Correspondingly, the effect
of technological changes in the electricity generation systemwill be slowand gradual,
at least in the short term, since most of the expansion will take place in developing
countries. These countries are more concerned about capital expenditure, utilisation
of proven technologies and cheaply available local coal fuel, rather than the global
environment and efciency considerations.
1.5.1 Future electricity generation technologies
Future technologies [10] will aim, particularly in OECD countries, at achieving the
(i) a high efciency to limit fuel use and emissions,
Global electrical power planning, investments and projects 13
(ii) clean emissions to reduce environmental impact,
(iii) low capital cost to limit investments and
(iv) limited capacities with short lead times and distributed sources to minimise
uncertainties and risks.
Modern CCGT ring natural gas, largely, meet most of these conditions. Nuclear,
hydro and renewable sources meet some of the conditions. Existing coal technologies,
however, are the least capable in honouring them. Therefore, the emphasis is on
developing environmentally sound and clean coal technologies, such as that offered
by uidised bed combustion (FBC) and zero carbon emission technologies. Advances
have been achieved in improving efciency of electricity generation, particularly in
recent years. However, to reduce CO
emissions further, new technologies for gas-
and coal-based combined-cycle generation are needed. A few such technologies are
currently available and their commercial application lies not far into the future. These
are, for example, pressuriseduidisedbedcombustion(PFBC), integratedgasication
combined-cycle (IGCC), and the topping cycle, as well as the zero carbon emission
technologies that are presently being developed.
1.5.2 Future electricity generation fuels
The major energy sources that currently dominate the generation of electricity (oil,
natural gas, coal, hydro, and nuclear) will continue for a few decades. As mentioned
earlier, this is because of the slow development of economically new and renewable
energy sources, and, of course, the vast existing stocks of facilities. Owing to its
high price, crude oil and its products will continue to diminish their share in elec-
tricity generation and, most likely, in absolute terms. The main utilisation of crude
oil will continue to be in the OPEC, and in small developing countries, which have
no local energy sources. Natural gas is an ideal fuel for electricity generation and,
correspondingly, it will increase its present share (16 per cent) of the electricity fuels
market. The prospects of it assuming a much larger share will be enhanced in the
case of future energy/carbon taxation and ratication of global environmental agree-
ments. Its use will, however, continue to be limited by the previously mentioned
factors and uncertainties about future gas prices. Coal is the worlds major fuel for
electricity generation and will remain so for many years to come. Its technologies are
well established, prices are cheap, and reserves abundant. Regardless of its pollution
problems, it will benet from the fact that most of the growth in electricity gener-
ation will be in developing countries that are relatively rich in coal, like China and
India. Developments in technologies for carbon sequestration will greatly enhance
the fortunes of coal.
The future of nuclear energy, regardless of its established technologies and
absence of gas emission, will continue to be handicapped by factors such as: lim-
ited public acceptability, large size of units, and huge investment requirements. It
must also be realised that its energy utilisation is limited to electricity production and
of the future growth in electricity requirements will mostly be in developing coun-
tries that, often, cannot meet the investment and technology requirements. Therefore,
for the future, and other than for unpredictable environmental events (surprises),
14 Economic evaluation of projects in the electricity supply industry
nuclear energys relative contributions towards global electricity requirements will,
most likely, not increase. At best, its present contribution of around 1617 per cent
will be maintained.
Like nuclear energy, hydro-energy can only be utilised for the production of
electricity. However, in contrast, hydro-energy has limited economically viable sites,
with most of the large sites already utilised. Other viable sites, like in Africa, have no
nearby loads. Therefore, its future proportional share of electricity production could
decrease. During the 1980s, hydro-energy grew at a handsome 2.3 per cent annually,
but this has limited future prospects, since newsites demand higher capital investment
and have a greater environmental impact.
The contribution of new and renewable energy sources such as solar, photo-
voltaic, wind, geothermal, etc., will be growing very fast in percentage terms but
their global utilisation will continue to be limited because of present limited facilities
and small unit size [21]. Solar energy, although abundant, is dispersed and inef-
cient and correspondingly expensive to exploit. This applies to almost all forms of
new and renewable energy sources for electricity production; however, wind energy
has shown recent economies of scale and solar cells are increasingly being used for
special applications. Even if there is a technological breakthrough in the future (which
is not yet evident), the effect will be gradual and limited, given the enormous stock of
existing generation facilities. Prospects for wind energy and solar cells (PV), which
have the best prospect for rapid growth, are detailed in Chapters 8 and 9.
1.6 Projects and capital investments
The electricity supply industry is highly capital intensive. It is probably more capital
intensive than any other sector, particularly in the developing countries. Therefore,
planning and proper nancial and economical evaluation of projects are important to
rationalise investment and achieve economic efciency.
A review of recent studies [5] indicated that there is a need to invest $2700 billion
(in 2000 dollars) in the electricity supply industry worldwide over the period 1995
2010, that is, $175 billion on the average per annum; this is equivalent to 120 billion
pounds sterling annually. Generation projects will account for 63 per cent of these
capital investments, transmission for 8.8 per cent, and distribution for 21.2 per cent.
The remaining 7 per cent will be general expenditure, mainly concerned with control,
telecommunications, and similar activities. Developing countries will account for
over 58 per cent of these investments, developed countries (OECD) for 32 per cent
and the Transitional Economies (East Europe and the former Soviet Union) for the
remaining 10 per cent, as detailed in Table 1.3.
1.6.1 Generation investment and projects
Most of ESI projects will be in generation, and will take place in developing countries.
To the existing stock of global generation capacity of 3580 GW in the year 2000, it
is expected that 1200 GW of extra capacity will be added, that is, an increase of at
least one third over 15 years. Of this, China alone is expected to account for almost
Global electrical power planning, investments and projects 15
Table 1.3 Capital needs by use and country type (in billions
of 2000 dollars), over the period 19952010
Type Generation T & D and General Total %
Developed 560 300 860 32
Developing 970 615 1585 58
Transitional 170 85 255 10
Total 1700 1000 2700 100
Source: modied from Reference [5].
20 per cent of the new generation capacity, by investing in 230 GW of new capacity
over the period. This is more than the whole extension of capacity of Western Europe
that is supposed to increase by 200 GW. Costs per MW of capacity vary from one
country to another, depending on the type of generation, fuels utilised, and more
importantly investments in environmental protection facilities.
For most of the new generating facilities, it is expected that 40 per cent will re
natural gas or LNG, 35 per cent coal-red capacity, and 20 per cent will be new
hydro-electric plants. The remaining 5 per cent can be in nuclear and new and renew-
able electricity generating facilities. However, coal-red generating plants, because
of their capital intensive nature, are expected to account for more than half of the gen-
eration capital investment. Generally, the 1200 GW of new generating plants (with
all environmental facilities) are expected to cost $1700 billion, which is an average
of $1400 kW
, i.e. 860 kW
in 2000 money.
Coal is expected to continue to be a favoured fuel for new power production
projects in many developing countries, since most of the new generating facilities
will be in south Asia and China which are rich in local coal resources.
Gas-red capacity is expected to grow proportionally faster than any other type.
Such facilities will increasingly assume the role of base load generation in almost
all regions of the world, except in south Asia and China, which have very little
natural gas reserves. Natural gas prospects can greatly be enhanced by the growing
environmental awareness. Hydro-electric power generation is also expected to grow
in China and Latin America. However, in some African countries, demand shortage
delays utilisation of the abundant hydro-power capacity, while in OECD countries
most of the economically exploitable sites have already been utilised.
Future nuclear power projects, over the same period 19952010, are expected to
be few (7080 GW), owing to the very high cost of nuclear facilities, long lead times,
and public awareness. Most of the new facilities will be in Japan, China, east Asia
and south Asia, and in Finland.
1.6.2 Transmission and distribution projects
As shown by Table 1.3, transmission, distribution, and general investments are
expected to amount to $1000 billion (660 billion) over the 19952010 period.
16 Economic evaluation of projects in the electricity supply industry
Most transmission projects will take place in developing countries, particularly Latin
America, where large transmission lines will be needed to convey electricity from
remote hydro-electric stations. Afewtransmission facilities will be needed in Europe,
where the network is well developed. Deregulation, unbundling of the transmission
network and difculties in getting way leaves are creating bottle necks in transmission
facilities in many developed countries.
Most developed and developing countries need to invest sufciently to extend
and improve their distribution networks. Losses in the distribution system include
most systemlosses in the developing countries. Projects to reduce losses and improve
the supply continuity will gure highly in developing countries distribution plans.
Therefore, it is expected that these countries will invest more than twice as much on
their distribution facilities compared with transmission. Strengthening and extension
of rural networks, in many developing countries, will be the centre of interest. At the
time of writingthere are some twobillionpeople, mostlylivinginrural areas, whohave
no accessibility to electricity supply. Providing them with electricity is the greatest
challenge facing developing countries in their pursuit of sustainable development.
1.6.3 Sources of investment funds
In 2000, the worlds Gross National Income (GNI) was around $31 171 billion
[22] (in purchasing power parity it was around $44 500 billion). It is expected to
increase to around $42 000 billion (2000 dollar) in 2010. With investments averaging
20 per cent of this GNI globally, the investments in the electricity supply industry
will average 34 per cent of the worlds total investments (gross capital formation)
over the next few years. As for the developing countries, this ratio is almost double;
the investments in the electricity supply industry will average 89 per cent of their
total investments. This is a heavy burden on the economies of most countries in the
world, particularly the developing countries.
In the past, self-nancing, as well as governments and development funds and
agencies, used to provide the required funds for investment in the electrical power
system, and this is still the case in many developing countries. Owing to privatisa-
tion and restructuring, markets are being called upon to provide most of the needed
investments in developed countries and, slowly but gradually, in developing coun-
tries. Investments in the electricity supply industry in OECD countries do not exceed
1.3 per cent of their gross domestic investment (GDI). Therefore, they represent no
practical problem. Developing countries, however, need to invest $1585 billion in
their electric power systems during the period 19952010. Because of subsidies and
low electricity tariffs, internal fund generation in these countries is limited. Govern-
ment capabilities to nance such infrastructural projects are becoming more limited,
owing to the increasing demand of the other more pressing social sectors (education,
health, poverty eradication, nutrition, etc.).
Ofcial Development Assistance (ODA) to developing countries has decreased
during recent years. Therefore, the nancing gap of electrical power projects is
increasingly being lled by calling on foreign private capital through attracting
investment and the nancial markets.
Global electrical power planning, investments and projects 17
Table 1.4 Investment in infrastructure projects with private
sector participation in developing countries by
sector and region 19901999 (billions of $)
Sector Region
Telecommunications 249 Latin America 286
Energy 193 East Asia 169
Transport 106 EE & Central Asia 63
Water and Sanitation 31 Middle East and Other 61
Total 579 Total 579
Source: Reference [22].
Recent studies by the World Bank have shown that, over the past decade, the
telecommunication sector attracted more private participation in developing coun-
tries followed by the energy/electricity sector, as detailed in Table 1.4. Most of these
investments went into Latin America. However, total private participation in energy
projects (including oil and gas) over the 19901999 period of $193 billion is small
compared with developing countries requirements of over $1585 billion over the
19952010 period.
It is not possible to ascertain how much of the above-mentioned private capital
is going into power development in developing countries. However, the electricity
supply industry attracts a sizeable amount of this capital and an increasing proportion
will have to be provided by international private capital. For this to be achieved, much
reform (privatisation and restructuring) and regulatory arrangements must take place
in developing countries. Three conditions are mandatory [23].
Governments must be committed and guarantee a nancially independent elec-
tricity supply industry.
Electric utilities have to perform in a nancially and economically viable way.
Investors (foreign as well as local) must be convinced that they will obtain a good
return on their investment, and will be able to repatriate these returns.
Correspondingly, the nancial and economical evaluation of projects in the electricity
supply industry, and the techniques for the calculation of return requirements, are
becoming increasingly important.
1.7 Epilogue
This book is written at a time of major change, which will reshape the future of
electricity, owing to the following considerations [23,24].
(i) Global environmental concerns, particularly regarding detrimental effects of
carbon emissions, are paramount. OECD countries, and increasingly other
18 Economic evaluation of projects in the electricity supply industry
countries, are seriously considering these concerns when making investment
decisions. With more environmental knowledge in the future, things may
become even tighter. However, this developing environmental awareness is
promoting demand management and an efciency drive that will greatly
inuence electricitys future.
(ii) There is uncertainty about the future of nuclear energy.
(iii) The transformation into market economies is now taking place, not only in
Central and Eastern Europe, but also in a growing number of developing
countries. This transformation, from central to market planning, will greatly
inuence the future electricity and energy use of these countries.
(iv) With the advancement in information and telecommunication, electricity trade
(locally and regionally) is becoming common. Electricity markets, similar to
nancial markets, are growing.
(v) There is a growing trend towards deregulation and privatisation of the electricity
sector in major electricity consuming countries, with signicant implications
of this on investment decisions and demand patterns.
(vi) There are advances in technology and efciency, particularly in medium-sized,
combined-cycle generating facilities.
(vii) There is a signicant level of capital shortages in most developing countries.
All the above factors are creating uncertainty in the electricity supply industry,
signicantly affecting investment decisions, and sometimes delaying them.
This calls for a more thorough evaluation of the nancial and economic impact
of projects in the electricity supply industry. There is a need to move from determin-
istic assumptions, for studying and modelling of future plans, into risk analysis and
mitigation and valuation of uncertainties. Least-cost planning based on determinis-
tic assumptions, does not explicitly evaluate economic costs and risks of failure to
achieve economic objectives. Therefore, the results of the investment are suboptimal.
Also, deterministic methods do not help in understanding the mechanisms that greatly
inuence investment decisions, like the discount rate and impact of environmental
factors. Such aspects will be dealt with in greater detail in the coming chapters.
1.8 References
1 JARET, P.: Electricity for Increasing energy efciency, EPRI J., April 1992,
17, (3)
2 GERHOLM, T. R.: Electricity in Sweden Forecast to the year 2050 (Vattenfal,
Sweden, 1991)
3 KHATIB, H.: Economics of reliability in electrical power systems (Technicopy,
Glos, 1978)
4 NAKICENOVIC, GRUBLER, and MCDONALD: Global Energy Perspectives
(Cambridge University Press, 1998)
5 Financing worldwide electric powers, can capital markets do the job?. Resource
Dynamic Corporation for US Department of Energy, April 19, 1996
Global electrical power planning, investments and projects 19
6 Senior Expert Symposium on Electricity and the Environment, International
Atomic Energy Agency (IAEA), May 1991, Helsinki, Finland
7 MUNASINGHE, M.: Energy Analysis and Policy (Butterworth, London, 1990)
8 BACON, R. W. and BESANT-JONES, J.: Global Electric Power Reform, Privati-
sation and Liberalisation of the Electric Power Industry in Developing Countries,
Annual Reviews Energy and the Environment. The World Bank, 2001
9 Siemens: Pictures of the Future Emission Certicate Trading, Siemens Picture
of the Future, Spring 2002
10 MINCHENER, A.: Coal comes clean, IEE Rev. Nov./Dec. 1991, 37, (11)
11 SIMON, M.: The road to environmentally compatible power and heat genera-
tion, ABB Rev., 3, (91)
12 Greenhouse gas emissions the energy dimension, OECD/IEA, Paris, 1991
13 BLARK and VEATCH: An Attractive Option, Electricity International,
May 2002, pp 2628
14 NADEL, S. and GELLER, H.: Utility DSM, Energy Policy, April 1996, 24, (4)
15 Energy, Electricity and Nuclear Power Estimates for the period up to 2020,
IAEA, Vienna, July 2001 edition
16 World Electric Power Plants (Utility Data Institute, Division of the McGraw
Hill, 2nd edn., and later editions, 1996)
17 KHATIB, H. and MUNASINGHE, M.: Electricity, the environment and sus-
tainable world development, World Energy Council 15th congress, Madrid,
September 1992
18 BOURDAIRE, J.-M.: The link between GNP and energy consumption, Oxford
Energy Forum, May 1995, 21
19 1996 World Energy Outlook, IEA, Paris, 2000
20 KHATIB, H.: Electricity in the global energy scene, IEE Proc. A, June 1993,
140, (1)
21 ARGIRI, M. and BIROL F.: Renewable Energy, Oxford Energy Forum, Issue
49, May 2002, pp 35
22 World Development Report 2002, The World Bank, Washington DC, 2002
23 MULLER-JENTSCH, D.: The Development of Electricity Markets in the Euro-
MediterraneanArea, WorldBankTechnical Paper No491, WashingtonDC, 2001
24 Energy and the Challenge of Sustainability World Energy Assessment, UNDP,
UNDESA, WEC, New York, September 2000
Chapter 2
Considerations in project evaluation
Projects involve investments that are meant to satisfy a demand, and to achieve an
engineering or economic purpose (usually better efciency or enhanced perform-
ance). Therefore, a project is a process of creating specied results. It is a complex
effort involving many tasks, to achieve a certain objective. Aproject is a non-repetitive
unique process withstart andendpoints, budgets andnancial plans, life-cycle phases,
and stages. Projects can be capital intensive (electrical power, energy, telecommuni-
cations), infrastructural, civil work intensive (transportation, water supply, etc.), and
people intensive (agriculture, education, nutrition, etc.) [1,2].
2.1 Project selection and evaluation
Project selection is a problem of allocation of scarce resources including capital,
skilled labour, management and administrative capacity, as well as other resources
(land, energy, etc.). In the electricity supply industry, most projects are rather
imposed on the industry by rising demand. However, there are many ways of sat-
isfying a demand, through building new generation facilities, repowering existing
facilities, strengthening the network, or rationalising demand by demand side man-
agement (DSM) plans. Many projects are prompted by the need to improve the
quality of supply to achieve better continuity or adequate system standards. Some
projects, for efciency improvement, are justied by economic and environmental
Therefore, the requirements for projects in the electric power sub-sector are more
focused and less diverse than those encountered in other sectors. Recently, with
deregulation and privatisation, a wider market has become available for entrepreneurs
and investors to sponsor projects, mainly generation projects in electricity utilities.
With increased globalisation, investor funds in the electricity supply industry will be
seeking global as well as local markets. Although some projects undertaken by inde-
pendent power producers (IPPs) have enough nancial and demand guarantees, like
take-or-pay clauses, they still contain an element of risk project cost, delays, plant
22 Economic evaluation of projects in the electricity supply industry
availability, etc. Therefore, project selection, analysis and evaluation are becoming
more important in the electricity supply industry than at any time in the past.
Project analysis is a method of presenting the choice between competing uses of
resources, and is done through analysis of information and data. Project evaluation
studies are meant to assist in the selection and design of new viable projects. A study
will evaluate the extent to which the project produces the intended results, the proper
technology, the least-cost alternative process, as well as the cost-effectiveness of the
project. It will also consider the engineering as well as the nancial risk and evaluate
the economic (social) cost.
2.2 Project development
The development of projects is a cycle involving three distinct phases: the pre-
investment, investment, and operational phases. Capital-intensive projects in the
electricity supply industry pass through these three phases with each of the rst two
phases divided into stages of planning, design engineering, and execution stages [3,4].
2.2.1 The pre-investment stage
The pre-investment stage begins with the identication of the need for the project
(demand that has to be satised by new generation facilities, or a bulk supply sub-
station, or an investment opportunity from an independent power supplier). This
preliminary identication is followed by a pre-feasibility study, which is viewed as
an intermediate stage between the identication of the project and a detailed feasi-
bility study. In the pre-feasibility study, a detailed review of the need for the project
and demand for its output is undertaken, as well as of the possibilities and alter-
natives (site, size, fuels, etc.). Therefore, at this phase, a lot of support studies are
undertaken: market and demand studies, fuel supply, cooling water, location stud-
ies including soil mechanics, environmental impact assessment, as well as nancial
and economic analysis into the selection of the least-cost facilities, technologies and
location, and protability of the project.
The feasibility study
The feasibility study should provide all data and details necessary to take a decision to
invest in the project. The feasibility study denes and critically examines the results
of the studies undertaken in the pre-feasibility stage (demand, technical, nancial,
economic and environmental). The results of the feasibility stage are a project where
all the background features have been well dened: size and location of the facilities,
technical details, fuels, network features, environmental impact and how to deal with
it, timing of the project, and implementation schedule. The nancial and economical
part of the feasibility study will cover the required investment and its sources, the
expected nancial and economical costs and returns.
It is not possible to draw a clear dividing line between the pre-feasibility and the
feasibility studies. The pre-feasibility study is concerned with dening the alternatives
Considerations in project evaluation 23
(demand, location, size, technology, fuels, costs and environmental impact), while
the feasibility study denes the project in a manner that allows implementation to
proceed. A typical outline of a feasibility study is shown in Table 2.1.
The feasibility study for large electrical projects (like building a new large power
station or a major bulk transmission network and substations), has not only to be
conned to the project, but has to look into the electrical power sector in which the
project will be operating (through undertaking power system analysis), the future
demand, and market for electrical power. The feasibility study has to undertake an
engineering analysis that looks into the technologies, the scope of the project, its tim-
ing and implementation arrangements, its management and manpower requirements,
and its nancial and economic viability.
In this book, we are mainly concerned with the nancial and economic evaluation
of projects to ensure their viability. However, it is essential to understand the impact
of the other four considerations in electrical power project feasibility:
(1) the sector;
(2) the market (demand);
(3) technology and engineering analysis;
(4) management and manpower.
These are briey dealt with below, to introduce the project evaluator to the different
aspects that need to be considered before undertaking a project. In such capital-
intensive projects, the nancial plan is of vital importance; it has to ensure that there
are enough funds to carry out the project into completion. Funds are needed not only
to nance the project cost, but also to provide the working capital and pay for interest
during construction, and for ancillary costs and expenses. In most such expensive
projects, beside the capital (equity) from the project owner, there are loans provided
by banks, nancial institutions, and development agencies. All of these needs to be
investigated, arranged and coordinated in the nancial plan.
Project appraisal
Apart from the project pre-feasibility and feasibility studies that are carried out by
the project owners, more evaluation, which is termed project appraisal, is executed
by the nanciers (other than equity owners like lending banks or development funds).
The idea of appraisal is to satisfy the nanciers as to the accuracy and soundness
of the feasibility study. Appraisal usually deals in depth with macro-economic mat-
ters, environmental impact, and externalities. These are costs and benets that are
outside the connes of the project itself, but affect other objectives or policies of
the country. Appraisal work is greatly assisted by having a properly prepared feasi-
bility study that covers every facet of the project. However, appraisal goes beyond
feasibility into considering policies, regulations, and other macro-economic consid-
erations and externalities. Appraisal will undertake a thorough economical (social)
evaluation of the project costs and benets, as well as carry out detailed sensi-
tivity and risk analysis; this is to ensure the nancial and economic viability of
the project.
24 Economic evaluation of projects in the electricity supply industry
Table 2.1 Typical outline of a feasibility study [3]
1. Introduction
2. The sectoral setting
(a) The industrial (electrical power engineering) sector and linkages to the rest
of the economy
(b) The sub-sector (e.g. the generation sub-sector)
(c) Issues and problems
(d) Proposals for change
3. The market, pricing and distribution
(a) The market
(i) Historic supply and consumption
(ii) Projected demand and supply
(iii) Market for the proposed project
(b) Transmission, distribution and marketing
(c) Pricing
4. The utility
(a) Background
(b) Ownership
(c) Organisational framework
(d) Management
5. The project
(a) Objectives
(b) Scope of the project
(c) Technical description
(i) Production facilities
(ii) Utilities and infrastructure
(iii) Ecology and the environment
(d) Manpower and training
(e) Major inputs
(f) Project management and execution
(g) Project timing
(h) Environmental impact and measures for environmental preservation
6. Capital cost and nancing plan
(a) Capital cost
(b) Working capital requirements
(c) Financing plan
(d) Procurement
(e) Allocation of nancing and disbursement
7. Financial analysis
(a) Revenues
(b) Operating costs
(c) Financial projections
(d) Break-even analysis
Considerations in project evaluation 25
Table 2.1 Continued
(e) Accounting and auditing requirements
(f) Financial rate of return
(g) Major risks and risk analysis
8. Economic justication
(a) Economic analysis and economic rate of return
(b) Linkages and employment
(c) Technology development and transfer
(d) Foreign exchange availability and effects
(e) Regional development impact
9. Agreements
The project appraisal, particularly when carried out by regional international
development agencies, leads to a thorough critical evaluation of the project and the
sector. It often comes out with suggestions and proposals that improve the projects
setup and enhance the future performance of the sector. Some of these proposals
are crucial to the success of the project, so that they are treated as covenants and are
incorporated in the nancing and loan agreement, and the effectiveness of the
loan agreement and its disbursement is conditional on the prior honouring of such
covenants. Therefore appraisal is not only benecial for the project but can also
lead to sector reforms that can have a bearing on the national economy and the way
it is managed. It can affect tariffs, management, importation laws and can also lead
to restructuring. This is the case in many developing countries that badly need to
nance their power sector and have to borrow extensively from lending development
institutions (like the World Bank) for this purpose.
It is not intended to detail each facet of project evaluation and appraisal, since
these are detailed elsewhere [58]. The emphasis will rather be on the nancial and
economical evaluation. However, here are some of the aspects and activities that are
investigated in the feasibility study and appraisals.
1 The sector
A study of the power sector involves a study of its development, organisation and its
linkages to the rest of the economy, the institutions working in the sector, and regu-
latory setup. In addition, the legislation, regulations, and incentive structure inside
the sector (that are likely to affect the project) are involved. The tariffs, their structure
and their prospect of change and the regulatory systemfor setting themare included in
the study, as are the sector policies and strategies, their effect and the interaction of the
project with these. Taxation and importation tariffs and policies are examined for their
impact on the project. During appraisals there may appear certain shortcomings in
the sector or in the regulatory system that warrant pointing out.
26 Economic evaluation of projects in the electricity supply industry
2 Demand (the market)
This will deal with power demand, its past development, present growth, and future
demand forecasts, and howthe project will enable satisfying these. Project evaluation
will look beyond the project into the system and how the electrical power system, as
a whole, will interact with the project and with the availability of the new supplies
and network. The demand study will also look into the shape of the demand, its tim-
ing, how it ts the load curve, and prospects for its modication. It will also look
into the tariffs that apply, and if they are satisfactory; and whether the project will
affect these. In the case of system strengthening projects, the study will involve an
assessment of the existing detrimental nancial and economic effects of the supply
interruption and its consequences. Future demand and market evaluation involve
predictions and, correspondingly, a measure of risk assessment that is important
in the nancial evaluation and in choosing the right technologies and sizes that
minimise the nancial risk.
3 Technical and engineering analyses
These are covered by the detailed studies referred to in the pre-feasibility stage. The
feasibility study highlights the least-cost solution to satisfy the project objectives
(usually satisfying the demand). Appraisal ascertains that the proposed technical
solutions are truly the least-cost ones and that costs, timing, and implementation
schedules are satisfactory. The engineering analysis looks into the project timing and
implementation schedule. The technical and engineering analyses are related to the
nancial and economic analysis, since these are intended to evaluate the technical
and engineering alternative that satises the demand at the least cost.
4 Management and manpower
This refers to the availability of technical and managerial staff to man the facilities
and ensure their proper operation, maintenance, and management of supporting facil-
ities: stores and inventories, transport, provision of services, etc. It also denes their
availability and costs, the training requirements for the staff and the implication of
all this on project costs.
2.2.2 The investment phase
Once the project is fully dened, successfully evaluated, appraised and the nance is
available, the next phase of project implementation the investment phase begins.
This has many stages.
Carrying out the organisational, legal and nancial measures to implement the
Basic, as well as detailed, engineering work.
Land acquisition.
Tendering, evaluation of bids and contracting.
Construction work and installation.
Considerations in project evaluation 27
Recruitment and training of personnel.
Plant commissioning and start-up.
Good project planning and management must ensure the proper implementation of all
the above stages well before the project start-up. Delays or gaps in implementation or
management can cause increased costs or other damage to the utility, the investors and
consumers. Execution schedules of different sections of the project need to be closely
prepared, coordinated, and monitored. Typically, a network plan with identication
of the critical path needs to be drawn out for the procurement, implementation, testing
and commissioning of large projects. Various methods have been developed for the
effective and balanced organisation of the investment phase, such as the critical path
method (CPM) and the project evaluation and review technique (PERT).
This phase involves disbursement and investment expenditures which need care-
ful assessment and evaluation. Such expenditures occur in the earliest years of project
evaluation and are not signicantly reduced by discounting. Therefore they have con-
siderable effect on the projects nancial viability. Their effect can be more important
than future nancial ows (which occur at the later stages of project operation) whose
importance is greatly diluted by discounting. Such disbursements and investment
expenditures have to match the nancing plan of the investment phase.
2.2.3 The operational phase
If the project is well planned and executed in the pre-investment and investment
phases, respectively, a few problems in the operational phase will be encountered,
other than the teething problems that are not uncommon in most new facilities. The
success of the project and its benets (protability), of course, depend not only
on good engineering and management, but also on sound nancial and economic
evaluation, during the pre-feasibility and appraisal stages. This sound nancial and
economic evaluation is the subject of the next few chapters.
Electrical power facilities have a long useful operational life. To ensure that such
facilities will survive their useful life demands proper operation and efcient main-
tenance that can involve high expenditure. All this will have been considered during
the evaluation stage. However, as mentioned above, the effect of expenditures in later
years of the project operation can have limited signicance in evaluation owing to
discounting, particularly if high discount rates are applied. It is, however, necessary
to dene the expected useful life of the project at the evaluation stage. This can be
greatly inuenced by prospects of technological change and obsolescence, as well
as by changes in the fuel market and environmental legislation in the case of power
generation. Such unexpected outcomes can be taken care of during risk analysis (see
Chapters 13 and 14).
2.2.4 Post-operation evaluation
It is useful, at a later stage, after project completion, to revisit the project to compare
the performance and results with project estimates. This mainly applies to demand,
cost, execution time and evaluation of impacts, as well as returns. Such post-operation
28 Economic evaluation of projects in the electricity supply industry
evaluation is routinely carried out by international development agencies, such as the
World Bank. However, it also needs to be carried out by utilities and investors. A
post-evaluation will educate the project planners and decision makers and widen their
scope for future project preparation, to minimise pitfalls and risks in the preparation
of other similar future projects. Unfortunately, other than for development agencies,
not much post-operation evaluation is carried out. Post-operation evaluation is vital
to enhance experience and reduce future risks.
2.3 Other considerations in project evaluation
Projects in the electricity supply industry, compared with other industrial and utility
projects, have a few distinct features.
They are highly capital intensive, more so than projects in any other engineering
sector. They also can have long lead time before they are operational. Therefore,
they demand thorough planning, timing and intensive nancial and economic
Power projects, particularlyelectricitygeneration, canhave serious environmental
impacts, whose mitigation can signicantly affect capital cost. A thorough envi-
ronmental assessment and costing are a necessity for all electrical power projects,
particularly generation.
Power projects have long useful lives; however, some of these projects may not
remain operational to the end of their useful life because of technological change,
public apprehension (nuclear power industry is an example), environmental
regulations, shortages in fuel availability, etc., as already mentioned.
Most of the power projects are an extension or strengthening of an existing large
electrical power system and network. New large investments, like a large power
station, will have a systemeffect whose operational and nancial impact extends
beyond the connes of the project to affect the whole system cost. This is a con-
sideration that has to be accounted for in large projects and demands sophisticated
system analysis and simulation.
Electrical power technologies are well known and proven. Demand and markets are
available and predictable, and tariffs can be regulated. Therefore the extent of risk
for investments in the electricity supply industry, although signicant, is lower than
the average market equity. Many electricity utilities are still monopolies, although
the picture is now changing in many countries. Because of their monopolistic and
regulated status they are shielded from most of the market risks (and also market
incentives). In such cases the risk of wrong, or non-optimal, decisions are shifted
fromthe utility to others, such as the consumer, through tariffs. It is therefore essential
that proper nancial and economic evaluation, in accordance with market criteria, is
carried out in order to ensure that the utility projects are viable in competition for
resources with the other sectors of the economy.
The above points, as well as other considerations, affect the nancial andeconomic
evaluation of projects in the electricity supply industry. They have to be considered
Considerations in project evaluation 29
and will be detailed in later chapters. The introduction of computer-based design
packages (on a large scale) into the design and drafting of specications and drawings,
particularly in case of power stations, have greatly reduced the lead time necessary
for designing and executing a power station. Thus, signicantly assisting in reducing
risks and lead times for new power stations.
Also, the shorter lead times for the increasingly popular CCGTpower stations and
their smaller sizes, which better t the load curve, have assisted in reducing risks of
investment in new facilities. This is assisted by the increasing use of modular designs
in power station projects where lead times are also considerably reduced.
The increasing role of IPPs has introduced new players into the electricity supply
industry. In utilities, the risk of investment is spread over many projects. The IPP
usually deals with a project at a time; therefore, risk management is paramount.
This can be achieved through all parties concerned agreeing to the mutual share of
nancial liabilities through a security package, which involves the many agreements
dening the project and outlining the obligations of the parties involved (government
guarantees, power purchase agreement, fuel supply agreement, insurance, etc.). Legal
arrangements are quite important in formulating such a security package. A typical
project structure is shown in Figure 2.1. This diagram explains the complexity of a
modern generation project [9].
Sponsoring group
Joint venture
Credit agreement
Fuel supply
Power purchase
Fuel supply
Power utility/

Equity guarantees
Implementation agreement
Figure 2.1 Typical project structure [9]
30 Economic evaluation of projects in the electricity supply industry
2.4 References
1 BREHRENS, W., and HAWRANEK, P. M.: Manual for the preparation
of Industrial feasibility studies. United Nations Industrial Development
Organisation (UNIDO), Vienna, 1991
2 AL-BAZZAZ, M.: Notes on project analysis and management for planners and
trainers. Economic Development Institute The World Bank, March 1995
3 DUVIGNEAU, J. C., and PRASAD, R. N.: Guidelines for calculating nancial
and economic rates of return for DFC projects. World Bank Technical Paper
No. 33, 1984
4 FROHLISH, E. A.: Manual for small industrial businesses. UNIDO, Vienna,
5 LITTLE, I. M. D., and MIRRLEES, J. A.: Project appraisal and planning for the
developing countries (Heinemann Education Books, 1974)
6 SQUIRE, LYN, and VAN DER TAK, HERMAN: Economic analysis of
projects (The Johns Hopkins University Press, 7th Printing, 1989)
7 RAY ANANDARUP: Cost-benet analysis (The Johns Hopkins University
Press, 3rd Printing, 1990)
8 LAL, DEEPAK: Methods of project analysis (International Bank for
Reconstruction and Development, Washington, DC, 1976)
9 WHEELER, TONY.: Risk Management for Independent Power. Asian
Electricity Power Generation Conference, Bangkok, Thailand, 1995
Chapter 3
Time value of money (discounting)
Projects in the electricity supply industry live for a long time. As already mentioned,
2530 years is a normal useful life for a conventional power station. The network lives
even longer. For power generation projects most expenditures, in the form of opera-
tional cost (fuel, etc.) and income occur after commissioning. Such future nancial
ows will occur during different times and circumstances. Correspondingly, these
will have different value of money than ows occurring during project evaluation.
Therefore, the time value of money (discounting) and the choice of a proper discount
rate is highly important for capital intensive long-life projects with large operational
cost, like those of the electricity supply industry.
3.1 Discounting
Generally, nancial ows (streams of expenditures and income) from projects do not
occur during the project evaluation [1,2]. They occur after a year, a few years, or
often after many years. Annual cash ows are the difference between money received
and money paid out, each year. Cash ows or nancial ows (outlays) occurring at
different times cannot be readily added, since 1 today is different from 1 next year,
and very different from 1 in 20 years time. Before dealing with nancial ows
occurring at different times, these have to be adjusted to the value of the money at a
specied date, which is normally called the base date or base year.
Therefore, an important factor to recognise in project evaluation is the time value
of money. A pound today is more valuable than 1 tomorrow and 1 tomorrow is
more important than 1 the day after, etc. There are many reasons for this.
Future incomes are eroded by ination; therefore the purchasing power of a pound
today is higher than a pound in a years time.
The existence of risk, an income or expenditure that occurs today, is a sure amount.
Future income or expenditure may vary from anticipated values.
The need for a return; by undertaking investment and foregoing expenditure today,
an investor expects to be rewarded by a return in the future.
32 Economic evaluation of projects in the electricity supply industry
An entrepreneur expects to gain a premium on his investment, to allow for the
following three factors: ination, risk taking, and the expectation of a real return.
That is, he expects to regain his money, plus a return that tallies with the market and
his estimation of these three factors.
Even if ination is allowed for, or ignored, money today will still remain more
valuable than tomorrows money because of risk and expectation of a reward by for-
going todays expenditure. To an investor, 1 today is more valuable than tomorrows
1, because it can be invested immediately and can earn a real income, that is, a return
higher than ination. Todays 1 will equal tomorrows 1 plus a real value.
Present valuing (discounting) is central to the nancial and economical evaluation
process. Since most of the project costs, as well as benets, occur in the future, it is
essential that these should be discounted to their present value (worth) to enable proper
evaluation. Present valuing will be carried out through discounting next periods
nancial outlay (F
) to its present value through multiplying it by a discount factor.
The discount factor is a function of the discount rate (r), which is the reward that
investors demand for accepting a delayed payment. It is also referred to as the rate of
return or opportunity cost of capital, so that
present value (PV) = discount factor F
where discount factor =1/(1+r). The discount factor is sometimes called the present
worth factor. It is dened as howmuch a pound in the future is worth today. Therefore,
with a discount rate (expected rate of return) of 10 per cent annually, the discount
factor for the rst years nancial outlay will be 1/(1 + 0.1) = 0.909, and 110
materialising after one year will equal to 0.909 110 = 100 today.
Similarly, an outlay at year 2 will have to be multiplied by 1/(1 + r)
and that
occurring at a year n will have a discount factor of 1/(1+r)
. Therefore, the discount
factor, in year n, is equal to
discount factor = 1/(1 +r)
and present value =F
discount factor = F
[1/(1 + r)
]. Therefore, 1000
occurring after 5 years, with a discount rate of 10 per cent, will have a present value
equal to 1000 [1/(1 + 0.1)
] = 620.92 today. Similarly, 1000 occurring after
30 years will be equal to 1000.0 [1/(1 +0.1)
] = 57.31 today.
In the same way, the process of discounting can be converted to a process of
compounding when it is required to present value past payments. The compound
factor is the reciprocal of the discount factor and is equal to (1 + r)
. Therefore,
a nancial outlay that occurred one year earlier has a present worth equal to (1 +r)
of the value of that outlay today. A payment of 1000 that occurred a year from now,
will have a present value of 1000(1 +0.1) = 1100 today.
Therefore, the discount factor [1/(1 +r)
] is universal, with n positive (+n) for
all future years and negative (n) for all past years nancial outlays, with n = 0
for the base year. For the ease of the analysis the term discounting will also mean
compounding, taking into account the timing of the outlay as mentioned above.
Time value of money (discounting) 33
It has to be emphasised that present valuing is based on compounding returns.
That is, the expected return (say interest rate) on the rst years money is also added
to the original investment and then the sum reinvested at the same interest rate. This
is different from simple return (simple interest), where interest is only paid on the
original investment. Therefore, in simple interest, with an interest rate of 10 per cent,
a 100 invested today is equal to 100 +10 after one year, 100 +10 +10 after
two years, and 130 after three years, etc. In compound interest payments, the 100
investment will equal to 100(1 + 0.1)
, 100(1 + 0.1)
, that is, 121 and 133.10
after two and three years, respectively. Compounding and not simple returns are the
basis for present valuing.
When the discounting or compounding procedure is applied to money, the rate (r)
is often referred to as a rate of interest. When the procedure is applied to economic
resources in a more general sense (the electricity supply industry), it is usually referred
to as the discount rate [3]. The discount rate is, therefore, a more general termthan the
interest rate. In most of the chapters of this book the term discount rate will be used.
3.2 Discounted cash ows
It is better if the net present valuing is stated in terms of discounted cash ows. Acash
ow has already been dened as the difference between money received and money
paid. Each years future cash ows can be discounted to their present value by dividing
them by the discount factor for that year.
Therefore, extended streamof cash ows M
, M
, M
, . . . , M
occurring at years
0, 1, 2, . . . , n has a present value of:
PV = M
(1 +r)
(1 +r)
+ +
(1 +r)

(1 +r)
In the special case of M
= M
= = M
= M
PV = M

(1 +r)
To give a simple example, consider a short-term project involving an investment
of 50 000 thousand at the beginning of each year over four years, starting today,
with a discount factor of 8 per cent. Its present value is equal to
PV = 50 10

1 +
1 +0.08
(1 +0.08)
(1 +0.08)

= 50 10
(1 +0.926 +0.857 +0.794) = 178 850.
As already mentioned, present valuing is a process of compounding returns. There-
fore, the same principles of discounting (compounding) are applicable for past
34 Economic evaluation of projects in the electricity supply industry
payments, and their present valuation. For instance, a cash ow M that occurred in
a past year n, has a present value of M
in todays money. The present value
of 100 paid three years before is equal to 100(1 + 0.1)
= 133.1 at a discount
(compound) rate of 10 per cent annually.
In the above example, if the investments occurred in the past four years, their
present value today will equal:
PV = 50 10
[(1 +0.08)
+(1 +0.08)
+(1 +0.08)
+(1 +0.08)] = 243 300.
This approach is quite useful in electrical power projects since, in some project
evaluations, the base year (i.e. the year 0, to which all payments are discounted) is
usually the year of commissioning. Therefore, future cash ows are discounted to
that year, while past ows are also compounded (discounted) to that commission-
ing year.
Because of discounting, the value of future cash ows becomes eroded signi-
cantly year after year, particularly if discount rates are high. In the above example,
at a discount rate of 10 per cent, a payment occurring in 30 years will have a present
worth of only 5.7 per cent of its value. If the discount rate is 15 per cent, then this
present worth is only 1.5 per cent, which is almost negligible. Therefore, in project
evaluation, the nancial streams of the rst few years have great signicance. These
need to be predicted with accuracy, because it is the money streams of these early
years that have greater real value and impact. Discounting greatly helps in reducing
the signicance of inaccuracies in predicting future long-term cash ows. However,
this entirely depends on the discount rate. A low discount rate will help to retain a
signicant value of future cash ows, while a high discount rate will render long-term
cash ows almost valueless today.
Discount tables, amortisation ratios, etc., are readily available in the literature
[3,4], and through modern nancial calculating machines.
3.3 Net present value (NPV)
Along the life of the project there will be two nancial streams: one is the costs
stream (which includes capital and operational cost (C)) and the other is the benets
stream(B). The two streams must contain all costs and benets for the same estimated
life frame of the project. The costs stream, being outward-owing cash, is regarded as
negative. The difference between the two streams is the cash ows the net benets
stream. The values of the net benets in certain years can be negative, particularly
during construction and the early years of the project.
Discounting the net benets stream into its present value, by multiplying each
years net benets by that years discount factor, will present the net present value
(NPV) of the project [5,6], as detailed in the example in Table 3.1, which utilises a
discount rate of 10 per cent. Notice that outward-owing cash (costs) are negative
Time value of money (discounting) 35
Table 3.1 NPV real terms
Year Cost Income Net
Net benets
discounted at 10%
1 40 40 1.100 44.00
0 110 40 70 1.000 70.00
1 10 40 30 0.909 27.27
2 10 40 30 0.826 24.79
3 10 40 30 0.751 22.54
4 70 70 0.683 47.81
(salvage value)
Net present value: 8.41
whereas inward-owing cash (income) is positive:

]/(1 +r)
Usually projects are undertaken because they have a positive net present value.
That is, their rate of return is higher than the discount rate, which is the opportunity
cost of capital. The calculation of net present value is the most important aspect
in project evaluation and its positive estimation, at the designated discount rate, is
essential before undertaking a project.
3.4 Accounting for ination in cash ows
Future cash ows can be estimated either in todays money and are usually termed
cash ows in real terms, or in the money of the date (year) in which they occur
and are termed as monetary or nominal cash ows. It is usually easier to predict
future cash ows in real terms, i.e. todays money, because todays information is the
best available. Utilising real terms will eliminate the need to predict another future
factor ination thereby reducing the number of the unknowns.
Nominal cash ows are quite important for commercial nancial statements and
accounts. They are used in the prediction of nancial statements allocations (depre-
ciation, interest, etc.), in order to arrive at gross prots and net prots (after allowing
for taxation and similar outlays). To arrive at nominal cash ows, predicted real cash
ows have to be inated by the expected ination rate.
In present valuing, a real discount rate has to be utilised if cash ows are in real
terms (todays money). A nominal (monetary) discount rate is utilised if cash ows
are in monetary terms that are in the money value of the year in which they occur.
Anominal discount rate is equal to the real discount rate modied by the ination rate:
nominal discount rate = [(1 +r)(1 +ination rate)] 1.
36 Economic evaluation of projects in the electricity supply industry
Table 3.2 NPV nominal terms
Year Nominal
Nominal net
discount factor
Net benets
discounted at 15.5%
1 38.1 38.1 1.155 44.01
0 110.0 40.0 70.0 1.000 70.00
1 10.5 42.0 31.5 0.866 27.27
2 11.0 44.1 33.0 0.750 24.79
3 11.6 46.3 34.7 0.649 22.54
4 85.1 85.1 0.562 47.81
Net present value: 8.41
Suppose, for instance, that a real discount rate, which allows for real return and a
risk of 10 per cent, is adopted. Ination is expected to be 5 per cent in the future.
Then the nominal discount rate will equal
[(1 +0.1)(1 +0.05)] 1 = 0.155, i.e. 15.5 per cent.
Because of their small values and as an approximation, a nominal discount rate equals
the real discount rate plus ination. If cash ows are in real terms then real discount
rate is utilised. If they are in nominal terms then the nominal discount rate is employed.
Net present value is the same when utilising both methods.
The cash ows of Table 3.1 can be presented in nominal terms by inating them
by the annual ination rate of 5 per cent as in Table 3.2.
This is the same result as that of Table 3.1, whichindicates that the real andnominal
cash ows will give the same net present value if the real and nominal discount rates
are properly utilised with each cash ow respectively.
It has to be noted that the expenditure in the year (1) in Table 3.1 was 40 in the
money of the base year (year 0). This is only equal to 38.1, i.e. [40 (1 + 0.05)
ination rate], in the money of year 1. The same applies to the estimate of the
salvage value, which is estimated at 70 in money of the base year and is equal to
(70 [1 +0.05]
) = 85.1 in the money of year 4.
In most of the analysis of this book, it is the real cash ows and the real discount
rate that will be used to discount streams of income and expenditure (past as well as
future). When values are available in the money of the day of the transaction (like
xed rent values, payments for xed rates and tariffs, xed price fuel contracts, etc.),
then these values have to be deated to the base-year money, and then discounted by
the real discount rate to their present worth.
In many power-generation projects it is the commissioning year of the project
that is termed as the base year. Prior to the base year many payments, usually project
investment cost, have already been incurred. These have rst of all to be presented in
the money of the commissioning year, then to be compounded (discounted) to their
present value by multiplying them with the compounding factor (1 + r)
. This is
Time value of money (discounting) 37
the same as multiplying them by the discount factor 1/(1 + r)
, where n here is
negative because it is prior to the base year. Cash streams occurring after the base year
(commissioning date), have to be presented in the base-year money and discounted
by multiplying them with the discount factor 1/(1 + r)
. Therefore, the discount
factor [1/(1 +r)
] is universal for all cash ows with n as negative for all ows prior
to the base year, positive for all ows after the base year, and zero for the base year.
For the ease of treatment, the term discounting will be universally used for both
compounding and discounting.
In the past analysis, we have assumed that price changes of operating costs as
well as revenues are going to change over time (inate) at the same rate. This may
not be true in many cases, since relative price changes do often occur. Different cost
categories, like fuel costs, may have different rates of change over time from other
costs like labour or other materials. In this case, future streams are presented in nomi-
nal terms utilising each cost or income item, and its expected ination rate. Real cash
ows are obtained by deating these by the average annual ination rate expected
during the projected period. Alternatively, the project cash ows are presented in
real terms with the stream of the cost or income item(s) expected to signicantly
deviate from the average annual ination rate, inated (deated) by the ination
differential between its anticipated ination rate and that of the average annual
ination rate.
3.5 Considerations in present valuing
The above analysis indicated that projects consist of nancial streams of benets (B)
and costs (C), which occur at different years through the life of the project. There-
fore, it is essential to understand how to deal with these streams, manipulate them to
allow for the computation of their net present value, and allow for comparison of the
different benets and costs. This section details various present valuing (discounting)
formulas and their utilisation. It recapitulates on the above analysis and introduces
new concepts. Future and past cash ow are termed M, and the discount rate is
termed r. These are all in real money, that is ignoring ination (if they are repre-
sented in nominal terms then the discount rate must incorporate the ination rate
as detailed above). The following are general rules that need to be understood by
all project evaluators, although all do not necessarily apply to the electricity supply
3.5.1 Future and past valuing
Future valuing (FV) of a present value (PV) means that the base year has been moved
into the future by n years. Therefore, the PV is occurring now at (n) years, from the
newbase year. The universal discount (compound) factor is maintained, with negative
n value, i.e. FV = PV[1/(1+r)
] = PV(1+r)
. A similar approach applies for
past valuing, which means that the base year has been moved into the past by n years.
The past value will equal PV [1/(1 +r)
38 Economic evaluation of projects in the electricity supply industry
3.5.2 Annuity factor
Present valuing of a stream of equal cash ows M:
PV =
1 +r
(1 +r)
+ +
(1 +r)
= M

(1 +r)
If we substitute a for M/(1 +r) and x for 1/(1 +r) then
PV = a(1 +x +x
+ +x
Multiplying both sides by x we have:
xPV = a(x +x
+ +x
Subtracting the second equation from the rst:
PV(1 x) = a(1 x
Substituting for a and x and then multiplying both sides by (1 +r) and rearranging
PV = M


r(1 +r)

The expression in square brackets in the above equation is the annuity factor, which
is the present value of an annuity 1 paid at the end of each of n periods, at a discount
rate r:
annuity factor =


r(1 +r)

Therefore, the annuity factor is the summation of all the annual values of the discount
factors over the period, i.e. annuity factor =

discount factor, and
PV = M annuity factor.
Thus, the present value of annual payments of 20 each, paid for 10 years, with the
rst occurring after one year, and at a discount rate of 8 per cent, is equal to
PV = 20


0.08(1 +0.08)

= 20 6.710 = 134.20.
In the above equation of the annuity factor, if the cash owis maintained to perpetuity,
then the annuity factor is reduced to 1/r and the present value of the perpetuity:
PV =
In the above example, if a bond has an annual payment of 20, which is permanently
maintained, then the present value of all future payments will be
PV = 20/0.08 = 250.
Time value of money (discounting) 39
If the above annual payments to perpetuity are increased year after another, by an
annual percentage g (like reinvesting the annual return by g per cent) then the present
value of the perpetuity becomes:
PV =
1 +r
M(1 +g)
(1 +r)
M(1 +g)
(1 +r)
+ .
It can be proven that the above equation, over a long period, can be reduced to:
PV =
r g
Therefore, and with the same assumptions of the above example, if we consider a
bond that pays 4 per cent in annual real return, and if this return is reinvested then the
PV of the perpetuity becomes:
PV = 20/(0.08 0.04) = 500.
The annual rate of return of r, compounded m times a year, amounts by the end of
the year to [1 +(r/m)]
Thus, an annual return of 12 per cent, paid as 1 per cent monthly, and with a return
at the same rate compounded, is equivalent to [1 +0.12/12]
1 = 12.68 per cent
Generally speaking, if the benets are spread continuously, then the above equa-
tion of [1 + (r/m)]
approaches e
as m approaches innity, where e is the base
for natural algorithms and is equal to 2.718. For a continuously compounded benet
or cost the end of the year value has to be multiplied by (2.718)
. Therefore, if the
interest in the above example is paid daily and reinvested, the compounded return
will equal approximately 12.75 per cent annually.
3.5.3 Capital recovery factor (CRF) or equivalent annual cost
An annuity factor is a means of converting a stream of equal annual values into a
present value, at a given discount rate (interest). A capital recovery factor (CRF)
performs the reverse calculation. It converts a present value into a stream of equal
annual payments over a specied time, at a specied discount rate (interest).
From the above equation of the annuity factor, it is possible to derive the CRF
or the equivalent annual cost. This is the amount of money to be paid at the end of
each year annuity to recover (amortise) the investment at a rate of discount r over
n years.
The equivalent annual cost M will be the reciprocal of equation of PV mentioned
earlier, i.e.
M =
annuity factor
annuity factor
= 1


r(1 +r)

40 Economic evaluation of projects in the electricity supply industry
For example, the equivalent annual capital cost of an investment of 1 million over
10 years, at a rate of interest of 12 per cent will be:
= 1 000 000


0.12(1 +0.12)

= 1 000 000 0.176 98 = 176 980 annually.

This is the same as the annual mortgage payment to acquire a house. Thus a house
costing 1 million, which has to be repaid over 10 years with an interest (mortgage)
rate of 12 per cent, will entitle 10 annual payments of 176 980 each.
To prove that the CRF is the reverse of the annuity factor, consider these equal
annual payments of 176 980 discounted over 10 years, at a rate of interest of
12 per cent. Their present value will be:
176 980 annuity factor.
The annuity factor from the Present Value Tables is 5.6502, so
176 980 5.6502 = 1 000 000,
which is the original investment.
When such payments are executed on a monthly basis, with a monthly rate of
interest equal to 0.01 per cent, and the payments are spread over 120 months, the
above equation becomes:
1 000 000


0.01(1 +0.01)

= 14 347 monthly.
For semi-annual payments the annual fee will be:
1 000 000


0.06(1 +0.06)

= 87 184 semi-annually.
The CRF is the sum of two payments. The rst is repayment of the principal
(amortisation) and the second is the interest on the unrepaid principal.
The annual CRF for 1 at an interest rate of 12 per cent and a period of four years
is 0.3292, as shown in the following schedule.
Principal Interest CRF (total)
1 0.2092 0.1200 0.3292
2 0.2343 0.0949 0.3292
3 0.2624 0.0668 0.3292
4 0.2941 0.0351 0.3292
1.0000 0.3168
It is very important to understand both the CRF and the annuity factor. They are
useful in daily nancial life and in quick comparison of projects and evaluation of
alternatives in the electricity supply industry, as will be demonstrated in Chapter 5.
Time value of money (discounting) 41
3.5.4 Grouping monthly and hourly ows
Not all costs and benets occur at the end of the year. The main benet of electricity
production, which is generation in kilowatt-hours (kWh), occurs continuously every
hour of the year. To accumulate these as a single generation gure at the end of the
year is an inaccurate approximation. Payments for salaries, fuel, etc., are costs that
are incurred monthly and continuously throughout the year. To lump them as a single
payment at the end of the year and to discount them will result in an underestimation.
To overcome this, such nancial ows can be presented in a monthly (or hourly) form,
which makes the calculation cumbersome. As an alternative, they can be lumped as
an annual ow at the middle of the year, which is a useful approximation.
As an example, consider generation from a plant of capacity of 1 kW. Its annual
continuous production is 8760 kWh, spread throughout the year, with 1 kWh every
hour. If this production is grouped as one gure at the beginning of the year, with an
annual discount factor of 12 per cent (hourly discount rate of 12 per cent/8760), it
will be equal to:



1 +


= 8255 kWh.
Grouping this at the end of the year will have a present value equivalent to:



1 +


= 9307 kWh.
Neither of these gures tallies with the annual generation of 8760 kWh, which is
recorded by the operators.
If both the gures above are discounted to mid-year at 12 per cent annual discount
rate they will be 8787 and 8765 kWh, respectively. Therefore, grouping all the annual
generation in its physical terms as one lump sum, in the middle of the year, is a
useful approximation. The same applies to other expenses (payments for fuel, salaries,
benets, etc.), which are approximately evenly distributed throughout the year. This
is the procedure, which was adopted by UNIPEDE in its comparison of the cost of
different generating facilities [7].
Therefore, if the commissioning year is the base year, then the cash ow of the
rst year has to be grouped at the middle of the rst year for present valuing purposes.
The second years cash ow is grouped at 1.5 years from the base year, etc. Deviation
from this, like the common practice of grouping all cash ows at end of the year,
causes errors.
3.6 References
1 GITTINGER, J. R.: Economic analysis of agricultural projects (The John
Hopkins University Press, 1982, 2nd edn.)
42 Economic evaluation of projects in the electricity supply industry
2 BREALEY, R., and MYERS, S.: Principles of corporate nance (McGraw-Hill,
3 Discounting and Measures of Project Worth, Development and Project Planning
Center, 1995, University of Bradford
4 The world measurement guide, The Economist, London 1980
5 KHATIB, H.: Financial and economic evaluation of projects, Power Eng. J.,
February 1996
6 DUVIGUEAU, J. C., and PRASAD, N.: Guidelines for calculating nancial and
economic rates of return for DFCprojects, International Bank for Reconstruction
and Development, Washington DC, 1984
7 Electricity generating costs for plants to be commissioned in 2000 (UNIPEDE,
Paris, January 1994)
Chapter 4
Choice of the discount rate
4.1 Introduction
The life cycle costs of a project and its feasibility, for a given output, depend on three
factors: (i) the investment cost, (ii) the operational costs, and (iii) the discount rate
utilised. Many planners think that the discount rate is the most important of these
three factors. It greatly affects the whole economics of the project and the decision
making, particularly in capital-intensive projects like those of the electricity supply
industry [1]. The discount rate almost governs the choice of the least-cost solution.
It also greatly affects estimation of the net returns from the project (net present value)
during the evaluation stage, the projects feasibility, and the decision to proceed
with the investment or not. A high discount rate will favour low capital cost with
higher operational cost project alternatives. A low discount rate will tend to weigh
the decision in favour of the high capital cost and low operational cost alternatives.
In spite of its crucial importance in project evaluation, it is surprising how little
effort project evaluators exert to research the proper discount rate needed for project
evaluation. Simultaneously, all the effort in estimating investment and operational
costs is rendered worthless by a deviation in the choice of the discount rates. Many
project evaluators usually take a specic discount rate, of their own choice, as appro-
priate and then try to cover up for its possible inaccuracies by sensitivity analysis.
Sometimes, owing to lack of clarity about discount rates, two (or more) discount rates
are chosen for evaluation [2]. Often, for government-sponsored projects, the work
of the planner is made easier by the authorities xing the discount rate (sometimes
Inmanycases, the internal rate of return(IRR) of the project is calculatedandif this
is considered to be appropriate by the investors (utilising their experience, hindsight
and possible available returns and risks of other projects), then a decision is taken to
proceed with the investment without having to resort to the detailed calculation of
an adequate discount rate. However, such a procedure does not allow the calculation
of the net present value of a project, or adequate comparison of different alternatives
(see Chapter 5).
44 Economic evaluation of projects in the electricity supply industry
4.2 The discount rate
The discount rate is the opportunity cost of capital (as a percentage of the value
of the capital). The opportunity cost of capital is the return on investments forgone
elsewhere by committing capital to the project under consideration. It is also referred
to as the marginal productivity of capital, i.e. the rate of return that would have
been obtained by the last acceptable project. In investment decisions, the opportunity
cost of capital is the cut-off rate, below which it is not worthwhile to invest in the
project [3].
The discount rate connotes the entrepreneurs indifference to the timing of the
return. If it is equal to 10 per cent, then the entrepreneur is indifferent to whether
he receives 1 today or 1.10 a year from today. This indifference is the basis for
engineering economics. To serve this purpose, the nominal discount rate should at
least be equal to a value which, after tax, would compensate the entrepreneur for
the following three objectives, which have already been mentioned in Chapter 3:
(i) reduction in the purchasing power of money which is brought about by ination,
(ii) provision of a real return, (iii) compensation for the extent of risk undertaken
by committing capital to this investment. The value of the nominal discount rate is
correspondingly a function of the above three factors: ination, risk-free real return,
and the extent of risk in the project. A real discount rate, which ignores ination,
is utilised if the cash ows are presented in the base-year money, as explained in
Chapter 3. When reference is made just to the discount rate, then it is the real
discount rate that is meant.
To demonstrate the importance of discount rates, the cases for nuclear and coal
power station were compared. The results of the evaluation are demonstrated in
Figure 4.1. The gure gives the price per kWh of output and shows howthe economics
3 5 7 9 11 13 15 17 19
Discount rate ( per cent)


Figure 4.1 Sensitivity of nuclear and coal power stations costs to discount rate [4]
Choice of the discount rate 45
of each alternative changes with the discount rate. At low discount rates less than
7 per cent, the nuclear alternative is cheaper. However, at a discount rate of 910
per cent or higher, it is denitely the coal alternative that is in favour, even at high
coal prices. Obviously, the discount rate is crucial in such decision making between
alternatives [4].
Nuclear Coal
Investment cost ( million) 1527 895
Operating costs kWh
0.37p 0.46p
Fuel cost kWh
0.45p 1.43p
From Figure 4.1 it is clear how, for evaluation purposes, the cost per kWh gener-
ated is greatly affected by the discount rate for high capital-intensive investments, like
those of a nuclear power station. The cost of 2p kWh
more than doubled when the
discount rate was increased from4 per cent to less than 11 per cent. Between these two
discount rates, the cost of each kWh from a coal power station, which is less capital
intensive but has a much higher operational cost, increased by less than one third.
Figure 4.1 demonstrates the important fact of the sensitivity of different types
of investment to the choice of the discount rate. It is clear that, because future net
benets are greatly reduced by the higher discount rate, the cost per kWh rapidly rises
for capital-intensive nuclear power stations more than it does for the less capital but
higher operating cost coal power stations. For low operating cost alternatives, like
nuclear, the high net benets are severely eroded by the high discount rate, while the
high front capital investment is compounded by the high discount rate to the base year
of commissioning. For the higher operating cost alternative, the net benets as well
as the front investment are smaller, and correspondingly the result is less affected by
discounting. The choice of the proper interest rate is crucial in such highly different
investment cost alternatives.
Because of the primary importance of choosing the right discount rate in any
project evaluation, this subject is dealt with in some detail in this chapter. In this
analysis, which is carried throughout utilising the projects real costs and benets, at
the base year prices, we are only concerned with the real discount rate (i.e. ignoring
ination). At this stage, taxation is also ignored.
4.3 Calculating the discount rate
In most countries, projects nanced by the government use a different discount rate
than those used by the private sector investors. Normally, government investments are
less risky, because they are mostly in regulated utilities and industries. The discount
rate of the private sector investments is inuenced not only by risk, but also by returns
in the bond market which can change signicantly from one period to another. Both
discount rates are, however, signicantly inuenced by availability of capital for
investment and the cost of borrowing.
46 Economic evaluation of projects in the electricity supply industry
4.3.1 Government nanced projects
For public projects, the discount rate is sometimes decided by the responsible
institutions in the government, which greatly eases the work of the planner of gov-
ernment sponsored projects. In the 1978 White Paper guidelines for nationalised
industries, the UK Treasury indicated that the required rate of return for the nation-
alised industries projects should be 5 per cent in real terms (this was at a time in which
the real returns of risk-free investment, like those of short-term government bonds,
was very close to zero). Later, in April 1989, this was increased to 8 per cent and in the
mid-1990s this required rate of return was adjusted to 6 per cent annually [5]. In other
countries, hindsight is employed. The cut-off rate is in the background thinking of the
decision maker. If the rate of return falls below a certain level (say, 10 per cent), the
project is deemed unacceptable. If it is higher than another level (15 per cent, for
instance), the project is held in great favour. The level of such rates depends on the
availability of capital and public funds for the government utilities to invest, and
the number and value of competing projects. It also depends on the availability of
loans for the public utilities and the rate of interest of such borrowing. It is usually
appropriate for the government to undertake the project as long as its rate of return
is higher than the real cost of borrowing. The actual cost of borrowing takes into
account the budget decit, the indebtedness of the government; that is, the public
local debt as well as foreign, and the capability of the government to repay this in
the future as well as other macro-economic considerations relevant to the role of the
government in the economy. Sometimes this discount rate is referred to as the social
discount rate.
International development agencies, such as the World Bank and other regional
development banks, also consider, during project appraisal, the macro-economic
situation of the borrowing developing country to assess the right discount rate to
apply in the case of that particular country. In their studies of the economics of
nuclear electricity generation, UNIPEDE/EURELECTRIC chose what it considered
to be two logical real discount rates, namely 5 and 10 per cent, and evaluated the
economies of different generation facilities utilising both of those discount rates. Of
course, this is only indicative. For decision making, a single discount rate has to be
chosen as a reference discount rate. This discount rate has to take into consideration
most of the points explained below. In case of business decisions it must be equal to
the opportunity cost of capital.
4.3.2 Business investment projects
Investors expect a rate of return from projects to compensate them for the following:
a minimum acceptable real return available in the market (risk-free rate of interest),
the risk of investing in the project, taxation and also ination. As explained above, the
rate of return will be calculated in real terms thus ignoring ination. Therefore, the real
returns fromthe project are estimated tocompensate the entrepreneur for the following
Choice of the discount rate 47
Table 4.1 Average rates of return on treasury bills, government bonds, corporate
bonds, and common stocks, 19261999 (gures in annual percentages)
Portfolio Average annual rate of return Average risk premium (extra
return versus treasury bills)
Nominal Real
Treasury bills 3.8 0.7 0
Government bonds 5.6 2.6 1.8
Corporate bonds 6.1 3.0 2.3
Common stocks (S&P 500) 13.0 9.7 9.2
Small-rm common stocks 17.7 14.2 13.9
Source: Ibbotson Associates, Inc., Yearbook.
(i) The risk-free rate of interest
The risk-free rate of interest measures the time value of money. The best measure
for measuring market risk-free rates of interest is the index-linked gilt. These gov-
ernment index-linked bonds (linked to the cost-of-living index) will yield to their
owners, annually, an interest that is equal to a risk-free rate of return and also com-
pensate them for ination. It is also possible to calculate the real risk-free rate of
interest by deducting ination from the nominal yield on conventional government
Table 4.1 features the average return on treasury bills and government bonds in the
United States, as well as US common stocks until 1999. From this table it is clear that
government bonds have a real return that averages around 2.63 per cent annually,
while the common stock has a risk premium of around 7 per cent above government
A return of around 3 per cent is therefore the minimum real return expected by an
investor when undertaking a risk-free investment, like putting money into government
(ii) Premium to compensate for risk
Equity is an ownership right or risk interest in an enterprise. Return from equity
(stocks) involves capital gains (or losses) as well as dividends. Investing in equi-
ties entails risk, equity prices, as well as dividend uctuations. Therefore, investors
in the nancial market (stock exchange) expect a premium over investors in gov-
ernment bonds to compensate them for the risk they are undertaking. The amount
of this premium depends on their and the markets evaluation of the risk of
the investment, as well as the availability of other remunerative outlets for their
Return on equities (capital gains plus dividends) uctuates in the stock mar-
ket. However, over the long term, the average equity expects to have a higher real
return than bonds. Otherwise, there will be no incentive to invest in the risky stock
48 Economic evaluation of projects in the electricity supply industry
exchange. The arithmetic mean of the return on the value-weighted index of all equi-
ties (the market portfolio) in the UK during the period 19551994 was 10.9 per cent
on the average annually, but this has dropped in recent years.
An almost similar picture exists in the USA, where the average risk premium
(extra real return of stocks over treasury bills) was around 9 per cent annually over
the lengthy period of 19262000 [6]. This gure similarly tallies with that of the
UK capital market experience, as well as other markets. Therefore, an average risk
premium of 89 per cent (say 8.5 per cent) above treasury bills, or 7 per cent above
government bonds is considered reasonable for the average equity.
The above situation applies for the average equity, i.e. to the market portfolio.
However, each category of investment has its own risk measure; investment in new
business ventures, depending on its technologies and markets, is much more risky
than the average equity. Simultaneously, regulated utilities have a risk, which is lower
than the average market risk. Astocks sensitivity to change in the value of the market
portfolio is known as beta. Beta, therefore, measures the marginal contribution of a
stock to the risk of a market portfolio. In a competitive market, the expected risk
premium varies in direct proportion to beta. This is the capital asset pricing model
(CAPM) [6], simply dened as
expected risk premium on a stock = beta expected risk premium on market.
Therefore, treasury bills have a beta of zero because they do not carry out any risk.
The average equity in the market portfolio has a beta of 1. Therefore, its risk premium
is the average market risk premium of 8.5 per cent.
Generally speaking:
expected risk premium on investment = beta average market risk premium
and real discount rate = real risk-free rate +(market risk premiumbeta).
Therefore, investment in an asset that has a beta of 0.6 means that the real discount
rate for this investment will be equal to 5.8 per cent (0.7 per cent (which is the risk-free
rate) + (8.5 per cent market risk premium 0.6)).
It is therefore necessary to discuss the beta of the electricity utilities. Utilities, in
many cases, are monopolies. They have well-dened markets and also established
technologies; correspondingly they have a lower beta than the average equity. Recent
beta for electricity generating companies in the UK was around 0.9 and that of the
Regional Electricity Companies was around 0.8. Beta of the mean equity for electric
generating utilities in the USA was much lower, at an average of 0.51. Betas for
Japanese utilities uctuated much more than that of UK and USA utilities. They were
as lowas that of the USAutilities until the mid-1980s, then increased, and were above
1.0 in recent years. Table 4.2 gives the beta of several large USA electric utilities.
Mean equity betas of American and Japanese electric utilities are in Figure 4.2.
Apparently, no general global gure can be put into the betas of electricity utili-
ties. Generation utilities have a higher risk and correspondingly higher beta value than
distribution utilities. Nuclear installations have a higher risk than other forms of ther-
mal generation and, correspondingly, utilities with nuclear generation have a higher
Choice of the discount rate 49
Table 4.2 Betas for some large electric utilities in the
Firm Beta Standard error
Boston Edison 0.60 0.19
Central Hudson 0.30 0.18
Consolidated Edison 0.65 0.20
DTE Energy 0.56 0.17
Eastern Utilities Associates 0.66 0.19
GPU, Inc. 0.65 0.18
New England Electric System 0.35 0.19
OGE Energy 0.39 0.15
PECO Energy 0.70 0.23
Pinnacle West Corp. 0.43 0.21
PP & L Resources 0.37 0.21
Portfolio Average 0.51 0.15
Source: The Brattle Group, Inc.
Figure 4.2 Mean betas of electric utilities in US and Japan [7]
- - - 69 US operators
9 Japanese operators
beta than other generating utilities, depending on the extent of their nuclear compo-
nent. Long-life facilities, like large coal-ring plants, carry more risk than modern
CCGT gas-ring facilities. Investments in big long-lead-time pulverised coal ring
generating units is riskier than investing in smaller short-lead-time CCGT plants that
easily t the load curve. Therefore, the risk of investment in electricity utilities in a
particular country compared with other equities in the nancial market depends on the
extent and type of regulation in the utility market in that country, the sort of business
of the utility (generation or distribution or both), the type of facilities utilised and
their expected life. Generally speaking, regulated utilities have a lower beta than the
50 Economic evaluation of projects in the electricity supply industry
average equity. Betas between 0.4 and 0.9 are normal for utilities depending on the
type of business and extent of regulation. The regulatory environment, in particular,
has a marked inuence on the beta of investment in electric utilities. However, betas
in different countries reect local factors and are not necessarily representative of
those of other countries.
(iii) Taxation and its relationship with the discount rates
Most of the previous discussion referred to post-taxation gures, since entrepreneurs
are interested in their real returns after taxation. It is, therefore, better to apply the
real required rate of return to post-tax rather than pre-tax cash ows. It is, how-
ever, necessary to calculate the relationship between pre-tax and post-tax required
rate of return, since cash ows are usually presented in pre-taxation gures. This
relationship depends on the depreciation policy of the rm (the annual writing
down allowance, WDA), as well as the annual cash ows in proportion to the
incremental initial investment. The relationship can be expressed by the following
equation [7]:
pre-tax return = post-tax return/[1 Tax rate (1 WDA/p)]
where p = incremental annual operating cash ow expressed as the proportion of the
incremental initial investment, or to put it in a simpler form:
pre-tax return = post-tax return

1 Tax rate

amount of depreciation
annual cash ow

Therefore, the post-tax return depends on the tax rate, tax exemption procedures, the
depreciation practices of the rm, as well as its annual cash ows. In all cases, pre-tax
discount rates should be higher than post-tax discount rates. For instance, for a utility
with a real post-tax return of 8 per cent, the required pre-tax return at a corporate
taxation of 35 per cent can be as high as 12.3 per cent, but normally less than that
after allowing for depreciation deductions.
Consider, for instance, an investment in a power station, which is supposed to
cost 100 million and last for 20 years, where the discount rate is 10 per cent, and
the tax rate is 30 per cent. Such a plant will need to have a net annual income to
the investors after tax of 11.7 million to justify their investment (this is the annuity
required to amortise an investment at a 10 per cent discount rate over 20 years). The
pre-tax returns will have to equal the after-tax return plus the tax, after allowing for
a tax allowance for depreciation (assuming a straight line depreciation of 5 per cent
annually, i.e. 100 per cent divided by 20 years).
Pre-tax return = post-tax return (11.7 million) +tax,
tax = (pre-tax return depreciation) tax rate of 0.3,
depreciation = 100 million/20 = 5 million,
substituting, the pre-tax return = 14.57 million.
Choice of the discount rate 51
Table 4.3 Forecast cash ows in millions of dollars for
the rm
Year 0 Years 120
Investment 100
1. Revenue 300
2. Operational variable cost 250
3. Fixed costs 15
4. Depreciation 5
5. Pre-tax prot (1-2-3-4) 30
6. Tax 9
7. Net prot (5-6) 21
8. Operating cash ows (4 +7) 26
Net cash ow 100 26
The assets are depreciated over 20 years in a straight-line method.
Tax rate is 30 per cent.
All gures of items 18 are annual gures.
Such a sum(fromthe Present Value Tables) corresponds to a pre-tax rate of return
of 13.4 per cent, which is signicantly higher than the expected post-tax opportunity
cost of money of 10 per cent.
Consider another example that utilises nancial statements. A rm that invested
100 million will have an expected annual cash ow forecast as in Table 4.3.
Whether the rm will proceed with the investment depends on the evaluation of a
positive net present value of future cash ows at the rms discount rate. Suppose that
the rms opportunity cost of capital (discount rate) equals 12 per cent after tax. Then
a cash ow of 26 million, over 20 years, at a discount rate of 12 per cent will equal

(1 +0.12)
= 26 annuity factor
= 26 7.47
= 194.22 million
(where 7.47 is the annuity factor obtained from the Present Value Tables).
The NPV of the investment is:
100 +194.22 = 94.22 million.
Therefore, since the NPV is positive at a discount rate equal to the opportunity cost
of capital, the rm will proceed with this investment.
52 Economic evaluation of projects in the electricity supply industry
(iv) Ination
All the above analysis was in real terms, i.e. ignoring ination. However, if the cash
ows are presented in nominal terms, i.e. in the money of the year in which they
occur, then the discount rate has also to be in nominal terms.
Generally speaking, in the earlier dened CAPM model the real discount rate can
be modied to nominal discount rate as follows:
nominal discount rate = market risk-free rate +(market risk premiumbeta).
Therefore, a utility operating in a utility market of beta 0.5, average market risk
premium of 8.5 per cent and a nominal market risk-free rate of 8 per cent, will have
a discount rate of:
8 per cent +(8.5 0.5) = 12.5 per cent.
4.4 Controlling the value of the discount rate [6]
From the above discussion, and after allowing for risk-free returns plus premium for
risk, ination and taxation, the discount rate can assume high values [6]. This can
affect investment in utilities like electric-power companies. It is, therefore, appro-
priate to consider ways of controlling the required rate of return for utilities. The
most important means is through capital structuring and regulating prices (electricity
4.4.1 Capital structuring
This involves raising a proportion of the capital required for investment through debt.
Debt, for sound utilities, carries an interest, which can be as low as (or only slightly
higher than) the market risk-free return on index-linked bonds, while the equity will
require a high return because of risk. Therefore, capital structuring through having
a signicant part of the investment capital required in the form of xed-interest loan
can signicantly reduce risk. However, it has to be realised that if there is a high
debt /equity ratio then this entitles higher risk for the equity. Servicing the debt will
be the rst priority for the cash ow, which means putting returns to the equity
capital at a higher risk. This means raising the beta of the equity, which may end in
approximately the same rate of return for the total capital investment, irrespective of
the debt /equity ratio.
Consider the case of a situation in which the real risk-free returns are 3.5 per cent,
with risk premium on the average investment 10 per cent, totalling 13.5 per cent.
If a power utility (with a beta of 0.6) is investing in a project totally by equity,
its post-tax real returns should at least equal 3.5 per cent + 0.6 10 per cent =
9.5 per cent. If the capital is raised by a debt/equity ratio of 1:1, with a debt of real
interest of 3.5 per cent, however, then the theoretical real cost of capital will become
Choice of the discount rate 53
0.5 3.5 per cent +0.5 9.5 per cent = 6.5 per cent. This assumes that beta for the
equity has remained constant. This is not the case, because the equity has become
riskier owing to the need to service the debt, prior to having any returns to the equity
holders. Beta may have to double to 1.2, so that the real return will remain roughly
equal to the original 9.5 per cent.
Because of the tax deductibility of interest payments (tax shield), the main advan-
tage of debt is the tax benet. This may vary signicantly fromone country to another.
Each countrys situation and its taxation system have to be studied independently.
Decision on the merits of tax deductibility of the interest rates and reduction of risk
(if any) has to be taken into account when considering capital structuring.
4.4.2 Transferring risk
It is possible to transfer risk from the utility to consumers, by allowing continuous
price (tariff reviews), which ensures that the equity holders will always get a decent
pre-agreed target rate of return. This will almost eliminate the risk from the utility.
A utility with regulated prices will have little risk and correspondingly a low beta and
a low discount rate. This may tempt the utility to invest in higher capital-intensive
assets, which will lead to higher costs to the utility and correspondingly higher tariff
to consumers. This means shifting utility investment decision risks (whether right or
wrong) to the consumers who have to pay, through the tariff, for the utilitys decisions,
i.e. the consumers now have to bear the additional risk of the investment to allow the
utility always to get its target rate of return. Such an arrangement will not only
shift the risk to the consumer, but will also prejudice the interest of other competing
operators and investors in the industry who may not have the same privileges of price
It is therefore essential when considering new projects and investments in regu-
lated utilities to insist on using, as a discount rate, the private sector rate of return as
employed in protable tax paying investor-owned utilities.
4.5 Other forms of the discount rate
4.5.1 Weighted-average cost of capital
For project evaluation in the United States, most utilities use the Revenue-
Requirements Method (RRM). It is a project evaluation method that discounts future
costs (revenue requirements) into their present value using the utilitys weighted-
average cost of capital (WACC). WACC is the weighted-average cost of the rms
equity and debt. The least-cost alternative is the project alternative with the lowest
present-value revenue requirement (PVRR), which is the lowest-cost alternative using
the WACC as the discount rate [8].
This use of WACCis not consistent with methods of evaluation that are advocated
by nance textbooks including this book. The WACC is an average between the cost
of borrowing and the acceptable return on the investors equity. Therefore, it reects
the overall cost of the utilitys funds at any point in time. It is not the opportunity cost
54 Economic evaluation of projects in the electricity supply industry
of capital and its utilisation as a discount rate is erroneous in this regard, because the
discount rate for present valuing has to be equal to the opportunity cost of capital.
The WACC does not reect risk. Therefore, it is erroneous to utilise it for comparing
projects of different risks like comparing a nuclear plant (high-risk project) with
a CCGT plant (low-risk project). The correct risk-adjusted discount rate for project
alternatives is their opportunity cost of capital. As dened at the beginning of this
chapter, in investment decisions, the opportunity cost of capital is the cut-off rate,
belowwhich it is not worthwhile to invest in the project. Normally the WACCis below
the opportunity cost of capital and it correspondingly favours higher investment-cost
project alternatives.
4.5.2 Utilisation of multiple discount rates
Different project alternatives have different risks. For instance, investing in a nuclear
power station is riskier than investing in a conventional power station. New technolo-
gies have a much higher risk than established technologies. Therefore, for choosing
the least-cost alternatives, more than one discount rate can be utilised, each for a
different alternative. Each alternative has a different beta, which can be evaluated
and incorporated in the CAPM model, to obtain a discount rate that is commensu-
rate with the alternatives risk. That will allow for a risk-adjusted discount rate for
each alternative, which assists in incorporating risk into evaluation of alternatives to
choose the least-cost alternative and also to evaluate the required risk adjusted returns
on investment. Risk assessment will be covered in detail in Chapters 13 and 14.
Multiple discount rates can be also utilised for different components of desegre-
gated costs. Operational costs of a project contain many components: fuel, salaries,
consumable and spare parts, local taxes and rates, insurance, etc. Each of these
has a different future risk. For instance, local rents and rates can be xed in real
terms and need not be discounted with a discount rate that incorporates a risk
element (beta is equal to 0). Fuel prices usually have much higher risk than any
other cost parameter, particularly if there are prospects of environmental legislation
that may entitle cleaner fuel versions (lower sulphur content, for instance) or plant
Such prospects are allowed for in the risk assessment. Alternatively, an ination
differential is incorporated in the fuel outlay, in the cost streamto cater for the possible
increase in prices of fuel over the general ination rate. For evaluation purposes, it is
much easier to utilise a composite discount rate for the costs stream, while allowing
for signicant cost items (like fuel) to be treated in a manner that tallies with their
possible variation from the general price increase trends.
4.6 Summary
The discount rate is very important in project evaluation and is a crucial factor in
deciding the feasibility of a project. Investments in projects involve risk. Therefore
entrepreneurs expect a post-tax real rate of return on their investment to equal the
Choice of the discount rate 55
income of risk-free bonds plus a premium for risk. This premium depends on beta,
whichis the ratioof the uctuationinthe price of similar assets tothe uctuations inthe
overall stock market. In recent years, the real returns on government bonds averaged
2.63 per cent annually, while the average risk premium in the stock exchange, both
in the UK and the US, was around 45 per cent [9].
The above post-tax rate of return has to be adjusted to a higher pre-tax rate of
return. This takes into account taxation rates and exemption procedures, as well as
the depreciation policies of the rm. If cash ows are in nominal, rather than real,
terms, then a nominal discount rate that incorporates ination has to be utilised.
Regulated utilities, like power companies, have a lower beta than the average
equity. This depends on the type of business (generation or distribution), the type of
facilities (conventional or nuclear), and the extent of regulation in the market. Such
betas vary from one country to another and usually fall between 0.4 and 0.9.
The extent of risk can be slightly reduced by capital structuring, through increas-
ing debt to equity ratio, and by transferring the risk to consumers, in a regulatory
system that allows for regular electricity tariff reviews. This will only shift the invest-
ment risk from the rm to the consumers. It is, therefore, essential when evaluating
investments in power utilities, whether public or private, that a rate of return (the dis-
count rate) that is equal to that utilised in protable tax paying investor-owned utilities
should be employed.
4.7 References
1 MACKERRON, G.: Nuclear Costs: Why do they keep rising?, Energy Policy,
1992, 20, pp. 641652
2 Electricity generating costs for plants to be commissioned in 2000 (UNIPEDE,
Paris, January 1994)
3 CHRISTIAN D. J., and PRASAD, R.: Guidelines for calculating nancial and
economic rates of return for DFCprojects (International Bank for Reconstruction
and Development, Washington DC, 1984)
4 DIMSON, E.: The discount rate for a power station, Energy Economics, July,
1989, 11, (13)
5 The economic appraisal of environmental projects and policies a practical
guide (OECD, Paris, 1996)
6 BEALEY, R. A., and MYERS, S. C.: Principles of Corporate Finance (McGraw
Hill, 2000)
7 DIMSON, E., and STAUNTON M.: New Plant and Financial Factors, The
review of the prospects of nuclear plant-consortium of opposing local authorities
submission: volume 4, September 1994
8 AWEBBUCH, S.: The Surprising role of risk in utility integrated resource
planning, The Electricity J., April 1993
9 Share valuations (Financial Times, London, March 14th, 2003)
Chapter 5
Financial evaluation of projects
5.1 Introduction
5.1.1 Evaluation of costs and benets
It is essential to recap on what was previously said in Chapter 3. During the life
of the project, there will be two nancial streams: one is the cost stream and the
other is the benets (income) stream. The two streams must contain all costs and
benets for the same estimated life frame of the project. In nancial evaluation of
small projects, the two streams will contain only the estimated actual cash costs and
benets of the project through its life cycle. The economical evaluation will inuence
the two streams, to include all the economic (social and environmental) costs and
benets of the project that can be evaluated. The difference between the two streams
is the cash ow, the net benets stream. The values of the net benets can be negative,
particularly during construction and the early years of the project. In later years, the
benets will usually exceed costs and the discounted net benets will be positive,
otherwise the project will not be undertaken.
It can be said that evaluation of costs and benets of large projects (these normally
demand equity, loans, andother nancial instruments) is carriedout onthree levels [1].
Owners evaluation
This is a straight evaluation. The owner is mainly concerned with cash ow and
considers all money owing in (income from sales, receipt of loans, and salvage
value) as positive and all money owing out (project cost, cost of operation, interest
and repayment of loan) as negative. The owner is interested in net benets and their
net present value in comparison with the value of the investment (equity). The owner
is concerned only with the return to equity.
Bankers evaluation
When analysing the project for loan consideration, the banker looks on it as one entity
irrespective of the division of the investment cost between loans and equity. The
58 Economic evaluation of projects in the electricity supply industry
banker evaluates the return on the total investment (equity plus loans) and considers
its protability. Therefore, the banker will consider the net present value of the whole
investment and not just the investors equity. The bankers evaluation integrates the
points of view of the loan providers and equity investors.
Economic evaluation
This goes beyond the bankers evaluation to include all the economic (social and
environmental) costs and benets that can be evaluated. That includes taxes, subsidies,
environmental and other external costs, as detailed later in Chapter 7. Such economic
evaluation is usually done by development banks and similar institutions, and also by
the concerned planning departments in the government.
5.1.2 Project nancial costs
There are three main kinds of costs. Those are investment costs, operating costs, and
working capital. Those costs are usually broken down into several different items as
discussed below.
Investment costs
The items included under investment costs are (i) initial costs, (ii) replacement costs
and (iii) residual values. Initial costs refer to those costs involved in construction and
commissioning, including land, civil works, equipment and installations. Replace-
ment costs refer to the costs of equipment and installations procured during the
operating phase of the project, to maintain its original productive capacity. Resid-
ual values refer to the value of these investment items (equipment, land, etc.) at the
end of the projects useful life. However, residual values are usually small and do not
have a major impact on decision making. Sometimes, as in the case of nuclear power
stations, decommissioning and dismounting represent a substantial cost, which can
affect evaluation.
Operating costs
Operating costs are a combination of xed and variable costs. Fixed costs will be
incurred whatever the level of productions, like salaries, cost of management, and
part of the maintenance cost. Variable costs will depend upon the level of produc-
tion and include those items like fuel and energy, water, lubricants, and part of
the maintenance cost (in the case of industrial projects, the cost of raw materials
is also included). In general, production will never start at the maximum capac-
ity of the project. Capacity utilisation may increase over time or may uctuate
according to time of day or to season. The variable cost will increase as produc-
tion increases and will stabilise when maximum sustainable production capacity is
reached. The total operating cost is the sum of the xed and variable cost. The
operating cost per unit of production falls as higher-capacity utilisation rates are
Financial evaluation of projects 59
Working capital
Working capital refers to the physical stock needed to allow continuous production
(spare parts, fuel, raw materials). The stock has to be built up at the commissioning
phase and before the beginning of the commercial operation. Usually, stock require-
ments are dened as one months worth of production. For power plants and network
projects, there is usually one component of working capital, which is the initial stock
of material necessary for commercial operation. But for industrial projects, there are
three components of working capital: (i) initial stock of material, (ii) work in progress
and (iii) nal stock of production.
For evaluation purposes, all project costs are calculated at the estimated constant
prices and costs (real terms) existing at a specic year the base year.
5.1.3 Financial benets of the project
Financial benets of the project are brought about by selling the project product. These
benets are usually equal to the amount of production multiplied by the estimated
base price. Not all projects in the electrical power industry imply production. Some,
like efciency improvement, lead to cost reduction, which is equal to the benet.
Others can have economic rather than nancial benet, as in the case of improvement
of the supply reliability, rural electrication, and environmental preservation.
In the electrical power industry, calculation of benets is not easy. A new power
station would normally not only increase production, but also contribute towards
reduction of the overall system cost of generation. It may also reduce system losses
and delay the implementation of some projects for network strengthening. Certain
projects are redundant and are made necessary by the need to ensure security of supply.
Rural electricationis normallya source of nancial loss, but has signicant economic
benets. Some improvements in power stations, like inhibition of emissions, incur
high investment, reduce electrical energy output and efciency, and yet have sound
economical (environmental) benets.
Owing to deregulation, privatisation and competition, estimating nancial ben-
ets (protability) of electrical power industry projects is becoming increasingly
important. Later into the book, examples will be cited that help in understanding the
methodology of estimating nancial and economical benets.
5.2 Least-cost solution
It is necessary to ensure that a project is protable and that its return is higher than
that of the opportunity cost of capital. Just as important, is to ensure that the project
is the least-cost alternative for attaining the required output [24].
The ESI is one of the best venues for using least-cost solution techniques, since
there is always more than one wayinwhicha project canbe executedsothat its benets
can be secured. The least-cost solution aims at evaluating all realistic alternatives,
nancially and economically, before deciding the alternative that can achieve the
project benets at the least cost.
60 Economic evaluation of projects in the electricity supply industry
Projects in the ESI are, in the main, mutually exclusive; that is, the implementation
of one project renders it technically or uneconomically feasible to implement another
Most day-to-day decisions in the electrical power industry involve nancial evalu-
ation to choose the least-cost solution (from mutually exclusive projects) for meeting
the demand or rendering the service. For instance, there are many alternatives for
meeting the need for more electricity generation: thermal power stations at different
sites using small or large units ring coal or gas, gas-turbines and combined-cycle
gas-turbines ring light fuel or natural gas, nuclear power stations, etc. Each alter-
native will have a different cost, cause a different system effect and lead to a new
overall system cost. The least-cost solution aims at nding out the alternative techni-
cal arrangement that meets the requirements of electrical energy with the least cost
to the utility, its site and timing.
The same applies to projects in the electricity network, sizing, timing of exten-
sions, their routes and locations. Adjudication of offers for electricity facilities, like
transformers where the highcapital cost of analternative canbe tradedagainst its lower
losses, is required. The evaluation involves computing the overall cost of each network
alternative (capital plus future cost of losses and other operational costs). Trading
capital cost against future operational costs and against system security is a main
criterion in nancial project evaluation and least-cost solution. Therefore, in most
electrical power engineering decisions, there is more than one alternative to achieving
the required result. The least-cost solution considers all these alternatives, evaluates
themand indicates the alternative with the least discounted overall cost over the useful
life span of the project. Appendix 1 details an example for evaluating the least-cost
alternative in choosing a transformer while trading capital cost against cost of losses.
In choosing the least-cost solution, we are concerned with the differences in the
present value of the cost of the alternatives (including their system effects if any).
In many cases, the benets (output) of each alternative are the same since all the
alternatives are supposed fully to meet the project. In this case we are concerned
with the evaluation and comparison of costs. However, if there are differences in
the amount of the energy output, then comparison of alternatives is carried out per
discounted kWh of electricity output, through evaluating over time the overall system
cost of the alternatives.
There are many methods for nancial evaluation and comparing alternatives. The
most important and useful ones are:
the present value method, and
the annual cost method (the equivalent uniform annual cost method).
5.2.1 Present value method
The present value (PV) method [5,6] aims at present valuing (discounting) all costs
and benets of the project or cash ows (net benets) to a specied date, the base
year. In this case, all cash ows prior to or after the base year are discounted to
the base year through multiplying by the discount factor [1/(1 + r)
] where n is
negative for years prior to the base year. All values are considered to occur at the year
Financial evaluation of projects 61
Table 5.1 Present valuing (all values are in thousand pounds)
Year Costs Income Net benets
Capital Operational Total Cash ows DR = 8% DR = 15%
1.50 100 100 100 112.24 123.32
0.50 50 50 50 51.96 53.62
0 Commissioning date
0.5 20 20 40 40 0
1.50 30 30 80 50 44.55 40.54
2.50 30 30 80 50 41.25 35.26
3.50 30 30 80 50 38.19 30.66
4.50 30 30 80 50 35.36 26.66
5 Residual value 60 60 40.83 29.83
Present value of net benets: 35.98 13.99
end. However, in most instances, the middle of the year may be the more appropriate
date for their aggregation, as already discussed in Chapter 3.
To give a simple example of aggregating ows at the middle of the year, consider
a project that is supposed to live for ve years after completion, is expected to have
the following two streams of cost and income based on the base-year prices, and at
two discount rates of 8 per cent and 15 per cent. The project will have a residual value
of 60 000 at the end of its useful life of ve years.
The example in Table 5.1 demonstrates the present valuing procedure. Costs and
benets are supposed to be evenly distributed over the appropriate months of the
years of the project. Therefore, these can be grouped in the middle of the year about
the commissioning date (base year). This project will have a net positive value of
36.07 thousand, at a discount rate of 8 per cent, but a negative value of 13.99
thousand, at a discount rate of 15 per cent. Correspondingly, the project is protable
if an opportunity cost of capital of 8 per cent is considered appropriate. The project
needs to be discarded if 15 per cent is the opportunity cost of capital. It is also
possible to avoid the discounting for the year plus half by choosing the base date to
occur yearly from the middle of each accounting year, as shown by the example in
Appendix 1.
The PV method is suitable for choosing the least-cost solution. The method dis-
counts the capital and future running costs of each considered alternative to its present
value, using the agreed discount rate that is the opportunity cost of capital. If there
is any salvage value for the alternative, its value after discounting to the base year is
deducted from the cost of this alternative. Different alternatives may have different
system effects, and correspondingly different costs. These have to be undertaken in
the evaluation. The alternative with the least present value cost, is the chosen least-cost
62 Economic evaluation of projects in the electricity supply industry
Table 5.2 Comparing alternatives
Year Alternative 1 Alternative 2
Cost () Production (kWh) Cost Production (kWh)
Actual Discount Actual Discount Actual Discount Actual Discount
1 10 11 0 0
0 100 100 0 0 150 150 0 0
1 50 45.45 500 454.5 50 45.45 500 454.5
2 30 24.79 1000 826.4 10 8.26 1000 826.4
3 30 22.45 1000 751.3 10 7.51 1000 751.3
4 30 20.94 1000 683 10 6.83 1000 683
5 10 6.21 1000 621
Sum 240 213.63 3500 2715.2 250 235.26 4500 3336.2
Cost per discounted kWh, for alternative 1 = 213.63/2715.2 = 0.0787; for alternative 2 =
235.26/3336.2 = 0.0705. (As explained earlier the base date was chosen so that the annual costs
and benets grouped at the middle of each year are at yearly intervals from the base date.)
In choosing the least-cost alternative, benets need not be presented in monetary
terms. In some cases, benets are better presented with the physical output of the
project such as number of units produced, tons of the output or any similar output.
This is particularly suitable in the case of an electrical power project, since most of
the benets are production of electricity as kWh, its multiples, or reduction of cost as
reduced losses or usage in kWh. The method is also particularly useful for comparing
alternatives with different lengths of execution time and different outputs (kWh). The
evaluated costs (capital and operational) and benets (in kWh) are discounted to the
base year. The least-cost alternative will be the one least discounted cost divided by
the discounted energy output. This is demonstrated using a 10 per cent discount rate
in Table 5.2. Alternative 1 is the least-cost solution.
5.2.2 Annual cost method (equivalent uniform annual cost method)
This is a useful and quick way for choosing the least-cost solution. It can help in
providing the right answer, supposing that certain assumptions and approximations
are possible.
In Chapter 3, the equivalent annual cost was dened as being equal to the amount
of money to be paid at the end of each year annuity to recover (amortise) the
investment, at a rate of discount r over n years. An annuity is a level stream of
cash ows that will continue for a specied number of time periods (years). The
annuity factor is the present value of all the annual values of the discount factors over
the whole period (annuity factor =

discount factor).
Financial evaluation of projects 63
The equivalent annual cost M will be equal to:
present value of the investment
annuity factor
where annuity factor =

1/r 1/(r(1 +r)


The same results can be obtained by multiplying the present value of the investment
by the capital recovery factor (CRF), since CRF is equal to [1/annuity factor].
Alternatively, the annual benets (B) of the project, if they are equal throughout
the years of the project, can be present valued by the same way:
present value of benets = annual benets (B) annuity factor.
The same applies to present value the annual xed operating cost (FC) and annual
running operational costs (OC), throughout the life of the project. If these are constant
every year (for a known output), these can be present valued as:
annuity factor (FC +OC).
Therefore, the present value of the total costs of the project throughout its useful life
will equal to:
project cost at base year +[(FC +OC) annuity factor]
and the total benets of the project = B annuity factor.
For electricity generation projects, such benets can be in the formof kWh. If benets
are in monetary terms then annual cash ows (net benets) are utilised.
The PV of a project with equal annual operational cash ows is equivalent to:
project cost at base year +(annual cash ow annuity factor).
(It has to be remembered that project cost is negative because it is an outward-owing
This is a useful and quick way for comparing alternative projects, and for approxi-
mately calculating the cost of production and prices. A good example is to compare
the cost of production from a power station utilising a combined-cycle gas-turbine
plant (CCGT) with that utilising steam-power turbines (ST) of a similar size. Installed
cost at commissioning of the CCGT plant is 500 kW
, and it has an expected life
of 20 years. The ST plant costs 1000 kW
with an expected life of 30 years. The
xed and running costs (fuel, operation and maintenance) are also 2.4p kWh
2p kWh
, respectively. Each plant will operate at full load; approximately 8000 h
annually for ST and 7000 h annually for CCGT. All these costs apply to the same
commissioning date.
64 Economic evaluation of projects in the electricity supply industry
Then, the production cost of each kWh fromthese two alternatives, with a discount
rate of 10 per cent, can be calculated as follows. The annuity factors for 20 and
30 years at 10 per cent discount rate are 8.514 and 9.427, respectively.
For CCGT: [(500 8.514)/7000] +2.4p = 3.24p kWh
For ST: [(1000 9.427)/8000] +2p = 3.33p kWh
Obviously, production from the CCGT power station is the least-cost alternative. The
above calculation can also assist in the assessment of the tariff to be charged for such
a production. An alternate way of calculation is to present value all the future running
cost of the alternatives, to present value the output in kWh (as benets), and make
the necessary comparison. Therefore, for the CCGT alternative (per kW of installed
PV of operational cost = 0.024p 7000 kWh 8.514 = 1430.4,
Total PV of costs per kW= 500 +1430.4 = 1930.4,
PV of benets (kWh) = 7000 8.514 = 59 598 kWh,
Cost per kWh = 1930.4/59 598 = 3.24p.
For the ST alternative:
PV of operational cost = 0.02 8000 kWh 9.427 = 1508.3,
Total PV of costs per kW= 1000 +1508.3 = 2508.3,
PV of benets (kWh) = 8000 9.427 = 75 416 kWh,
Cost per kWh = 2508.3/75 416 = 3.33p.
This alternative method of assessment yields the same result as above.
This is a quick method that gives rapid results and allows the attention of the
evaluator to focus on a few alternatives. However, it involves many assumptions and
approximations that need to be handled carefully. Therefore, such quick methods
have to be elaborated further to consider other detailed issues (exact commissioning,
system effects, environmental impacts, long-term prospects, etc.) to allow accuracy
in decision making.
The choice of either the PVor the annual cost method for evaluating the least-cost
alternative is a matter of personal convenience. In the United States, the annual cost
method is preferred. Its implications are easier to understand for business decisions,
and it is easier to compute for regular annual series of disbursements; particularly if
the capital is obtained through loans. In the electrical power industry, annual costs
are irregular, utilisation varies from one year to another, and most decisions affect
the overall system cost. To allow for more detailed evaluation of future costs, the PV
method is preferred for identifying the least-cost solution since it allows for variations
in output, operating costs over time and other factors.
Financial evaluation of projects 65
5.3 Measuring worth of the investment
Many of the projects in the electrical power industry are forced on the planner and are
beyond his control; examples are building new power plants to meet load increase,
providing newfacilities to enhance security of supply, rural electrication, etc. There-
fore, many decisions in the electrical power industry are restricted to the choice of the
least-cost solution. With the privatisation of utilities and market economies, a more
thoroughanalysis of the protability of investment is alsobecomingessential. Projects
are carried out because they are needed, they are the least-cost solution, and they are
protable. It is now becoming increasingly necessary not only to weigh the benets
of the investment through a costbenet analysis, but also to carry out nancial prof-
itability projections. This includes forecasting three summary statements: (i) the pro
forma income statement, (ii) the pro forma balance sheet and (iii) the pro forma funds
ow statement [7]. Such statements will allow assessment of nancial protability to
In this section, we are concerned with the traditional costbenet analysis of
projects to assess their acceptability to utilities, governments, investment bankers
and development funds. There are several ways of assessing whether the project is
worth undertaking. The most useful of these are:
(i) computing the internal rate of return
(ii) evaluating the net present value of the project
(iii) calculating the benet/cost ratio
(iv) other criteria (pay back period, prot/investment ratio, commercial return on
equity capital).
All the above criteria, except for the last, involve discounting.
5.3.1 Internal rate of return
Calculating the internal rate of return is a popular and widely used method in the
evaluation of projects. The internal rate of return (IRR) is the discount rate that
equates the two streams of costs and benets of the project. Alternately, it is the rate
of return r that the project is going to generate provided the stream of costs (C
and stream of benets (B
) of the project materialises. It is also the rate, r, that would
make the NPV of the project equal zero, i.e. IRR is such that:

/(1 + r)
] =

/(1 + r)
If IRR is equal to or above the opportunity cost for a private project, or the social
discount rate (as set by the government) in public projects, then the project is deemed
worthwhile undertaking. Utilities, governments and development funds set their own
criteria for the opportunity cost of capital and for the social discount rate below
which they will not consider providing funds. Such criteria depend on the amount
and availability of required funds. Criteria also depend on the presence and expected
return of alternative projects in other sectors of the economy, the market rate of
66 Economic evaluation of projects in the electricity supply industry
9% 10% 11% 12% 13%
Figure 5.1 Calculating the IRR by interpolation
interest, and the risk of the project. In Chapter 4, the concepts that govern the choice
andxingof the discount rate were discussed. For some investors, the discount rate can
be viewed as the minimumacceptable rate of return belowwhich a project is rejected.
Therefore, if the IRR is equal to or above the minimum acceptable rate of return, then
the project is considered to be worthwhile undertaking. The IRR can be calculated
by trial and error calculations, through the utilisation of the above equation until r is
found or can be interpolated. However, preferably, it can be calculated through the
use of a computer program or a modern nancial calculating machine.
Alternately, it can be computed using a graphical method. Two points may be
plotted on graph (Figure 5.1) and joined by a straight line. The point at which this
line cuts the horizontal axis (i.e. where the NPV is zero) gives the IRR. The IRR for
the example in Table 5.3 is shown.
The IRR concept has certain minor weaknesses that have been explained in the
literature [8,9] and can sometimes be defective as a measure of the relative merits
of mutually exclusive projects. It also contains an important underlying assumption,
that all recovered funds can be reinvested at an interest rate equal to the IRR, which is
not always possible. However, the IRR is a widely understood concept and it largely
represents the expected nancial and economical returns of the project. Also most of
the weaknesses referred to do not normally occur in the electrical power industry. The
main merit of the IRR is that it is an attribute of the project evaluation. Its calculation
does not involve an estimation of a discount rate. Therefore, the evaluator avoids
the tedious analysis of Chapter 4. It is satisfactory to calculate the IRR and compare
it with the test rate conceived, which is a supercial attractiveness. Therefore, it is
a widely used means of assessing the return of the project in the electricity supply
Financial evaluation of projects 67
Table 5.3 Calculating benets
Year Cost Income Net benets Net benets
discounted at 10%
1 40 40 44
0 100 +10 40 70 70.00
1 10 40 30 27.27
2 10 40 30 24.79
3 10 40 30 22.54
4 70 70 47.81
Net present value: 8.41
5.3.2 Net present value (NPV)
The concept of net present value has already been fully explained. The method dis-
counts the net benets (cash ows), i.e. project income minus project costs to their
present value through the already assigned discount rate. If the net result is higher
than zero, this proves that the project will provide benets higher than the discount
rate and is worthwhile undertaking.
For example: consider the same project in Table 3.1, with the following present-
day following costs (investment 140, annual running cost 10) and income (benets)
of 40. The project is expected to last four years and the prevailing discount rate of
10 per cent is used.
Calculating the IRR: since the NPV at 10 per cent is positive, then the discount
rate is greater than 10 per cent. Trying 12 per cent, the NPV is 1.76; at 13 per cent
the NPV = 1.47. The IRR is, therefore, around 12.5 per cent. Since it is higher
than the minimum acceptable return of 10 per cent, the project is acceptable.
Finally, we consider the NPV: since the NPV > 0, the project is acceptable.
The method of the NPV is a powerful indicator of the viability of projects. How-
ever, it has its weaknesses in that it does not relate the net benet gained to the capital
investment and to the time taken to achieve it. In the above example, it does not matter
if the 8.41 were obtained through investing 100 or 1000, or obtained over 4 years
or 40 years. However, it is very useful in choosing the least-cost solution, since it is
the alternative that fulls the exact project requirements and has the higher NPV that
is preferred.
5.3.3 Benet/cost ratio
This method compares the discounted total benets of the project to its discounted
B/C =

B/(1 +r)

C/(1 +r)
68 Economic evaluation of projects in the electricity supply industry
Only projects of B/C 1 are adopted. This criterion is popular and, in some appli-
cations, is more useful than the net present value, in that it relates the benets to
costs of the projects. It also has a useful application for capital constraint, when
the industry has a lot of feasible projects but limited investment budget. In this case
projects are ranked in accordance with their B/C ratio and are adopted accordingly
until their combined costs equal the capital investment budget. Therefore, it is useful
in comparative analysis.
It has to be remembered that B/C is a ratio, while NPV is measure of absolute
In the example of Table 5.3:
value of discounted benets are = 40 +36.36 +33.06 +30.05 +47.81 = 187.28,
value of discounted costs are = 44 +110 +9.09 +8.26 +7.51 = 178.86,
B/C ratio = 187.28/178.86 = 1.047.
5.3.4 Other non-discount criteria for evaluation
There are many other criteria for evaluating the projects worth and return of invest-
ments. The most common methods are the payback period and prot/investment ratio
5.3.5 Payback period
The payback period is dened as the time after initial investment until accumulated
net revenues equal the investment, i.e. the length of time required to get investment
capital back. The method is used as an approximate measure of the rate at which
cash ows is generated early in the project life. It is utilised for small investments,
like improvements and energy efciency measures, since it is easy to understand
by business managers. However, in isolation, it tells the analyst nothing about the
project earning rate after payback and does not consider the total protability or size
of the project. It also ignores ination and discriminates against large capital-intensive
infrastructure projects with long gestation times. Therefore, it is a poor criterion in
itself and it must be used in conjunction with other criteria.
In the previous example of Table 5.3 the payback period is higher than three years.
5.3.6 Prot/investment ratio
The prot/investment ratio is the ratio of the projects total net income to total invest-
ment. It describes the amount of the prot generated per pound invested, and is
sometimes referred to as protability index. The idea is the selection of the project
that maximises the prot per unit of investment. The ratio is easy to calculate, but
does not reect the timing at which revenues are received and prots generated.
Therefore, it does not reect the time value of money. Correspondingly, it is not a
proper evaluation measure. In the example of Table 5.3 the prot/investment ratio is
50/140 = 35.7 per cent.
Financial evaluation of projects 69
5.4 Owners evaluation of protability commercial
annual rate of return
At the beginning of Section 5.3 it was explained that, for an investor to assess com-
mercial protability, forecasting a pro forma income statement through conventional
nancial accounts is necessary.
Therefore, it is possible roughly to evaluate the protability of the equity invest-
ment from the commercial viewpoint of the investor through calculating the equitys
prot by nancial accounts. A year is chosen at which the project matures, and the
net prot of the project is calculated for that year. Net prot is equal to income less
operational expenses, depreciation, interest, taxes, and other expenses. This is com-
pared with the total share (equity) capital invested and is the commercial return to the
The same approach can be utilised for assessing the return on the total investment
(equity plus loans). In this case the net prot, for commercial purposes, will be equal
to income less operational expenses, depreciation, taxes, and other expenses. Interest
is not included, since interest is the return on the loans. This net prot is divided by
the total investment to calculate the commercial return of the whole investment.
Such commercial accounts are not the criteria for proper project evaluation for
several reasons; mainly because they do not account for the time value of money.
Depreciation is used as cost of capital invested, and depreciation does not adequately
account for the declining value of money or for ination. Accountants measures of
protability are not well suited for ex ante project evaluation, especially for non-
commercial projects.
Evaluation methods that do not involve the time value of money (discounting) are
poor indicators. They provide approximations and should not be utilised for least-cost
solutions, or evaluating large investments.
To summarise: the guiding principle for project evaluation is the maximisation of
net present value while utilising, as a discount rate, the opportunity cost of capital. The
internal rate of return is not the only criterion for evaluating projects for investment
decisions. Net present value with a proper discount rate (reecting the true opportunity
cost of capital) is a criterion. With limited budgeting a benet/cost ratio has to be
calculated to assist in prioritising projects.
5.5 References
1 Discounting and Measures of Project Worth, University Of Bradford, Develop-
ment and Project Planning Centre, 1995
2 STOLL, H. G.: Least-cost, electric utility planning (John Wiley and Sons Inc.,
3 TURVEY, R.: Optimal pricing and investment in electricity supply (George
Allen & Unwin Ltd., 1968)
4 BERRIE, T. W.: The economics of system planning in bulk electricity supply
in TURVEY, R.: Public enterprise (Penguin Book, 1968)
70 Economic evaluation of projects in the electricity supply industry
5 NORRIS, T. E.: Economic comparisons in planning for electricity supply, Proc.
IEE, March 1970, 117, (3)
Inc., 2000)
7 DUVIGNEAU, J. C., and PRASAD, R. N.: Guidelines for Calculating Financial
and Economic rates of return for DFC projects, World Bank technical paper 33
8 LEAUTAND, J. L.: On the fundamentals of economic evaluation, Eng. Econ.,
19, (2)
9 JEYNES, P.: Fundamentals of accounting/economic/nancial evaluation,
Eng. Econ., 20, (4)
Chapter 6
Considerations in project evaluation
Apart from discounting and least-cost evaluation, there are many considerations in
project evaluation. These include: allowing for contingencies, timing of expenditures,
sunk costs, depreciation and interest charges. There are also other considerations
relating to system linkages, dealing with projects of different lives, and expansion
projects. Such considerations are discussed in the following sections.
6.1 Base cost estimate and contingencies
The base cost estimate [1] done at the evaluation stage is the best judgment of the cost
of all project components at the specied evaluation date. It assumes that these compo-
nents are accurately known and properly costed. If certain cost estimates are rough,
then that indicates the need for further investigations to assess accurately project
cost components. The period for project implementation and the commissioning date
should be estimated.
The best estimates of project costs can be undertaken from prices available at the
time of estimation (date of evaluation). Project implementation can take many years.
Hence, the actual cost of the project at the commissioning date will differ from the
cost estimated at the time of planning and evaluation. This is the result of ination and
increase in prices and quantities of the project components. Such variation is allowed
for through the following two contingencies.
(i) A physical contingency to allow for the increase in quantities of material and
equipment involved in project execution and the change of implementation
(ii) A price contingency to allow for increase in price of project components, over
the base case estimates, during the construction period.
6.1.1 Physical contingency
The physical contingency reects possible changes in quantities and implementation
procedures. The amount of physical contingency depends on the type of the project
72 Economic evaluation of projects in the electricity supply industry
components. Civil works have a higher contingency than machinery, to the extent
of detailing in project estimate preparations. Physical contingencies usually vary
up to 10 per cent of the project base cost. Beyond this, a more detailed estimate has
to be undertaken in order to reduce uncertainties in project cost estimation. Physical
contingencies are distributed along the projects execution life as a percentage of
annual cost allocations.
6.1.2 Price contingency
The price contingency allows for the increase in unit prices of the project compo-
nents, beyond the estimated prices of the planning year. It is highly dependent on
ination rates and other possible price increases. This allows estimating project cost
disbursements in the money of the year at which they occur. The sum of these annual
disbursements including price and physical contingency give an idea of project cost
for formulating a nance plan. The full nance plan will include these costs plus the
interest during construction and working capital. This indicates the amount of money
needed to be raised and procured to nance the project. However, the project cost for
nancial and economical evaluation purposes is not indicated, since the nancing plan
involves adding money of different dates and correspondingly different real values.
The base project cost is that project cost estimated in the money of the planning year
(or the commissioning year).
If the project cost is distributed along the years of the execution period and is
desired to utilise the commissioning date as the base year and to present the project
cost in the money of that year, then the anticipated annual disbursements, during the
project execution period (which include both physical and price contingencies), are
compounded to that year by the nominal discount factor (which includes the discount
rate plus ination). The example of Table 6.1 assists in explaining this. An alternative
arrangement, if the project is estimated as a lump sum in the money of the planning
year and it is desired to have the commissioning date as the base year, is where the
planning year estimates are compounded to the commissioning date by the nominal
discount rate with the physical contingency added, and these project costs are then
represented in the money of the year of commissioning.
For example, consider a project that takes three years for execution, and costs 100
at the base year (the present year of planning). Investment is grouped to be disbursed
Table 6.1 Financing plan
Year Base Physical contingency Price contingency Total
1 20 2 1.1 23.1
2 40 4 4.5 48.5
3 40 4 6.9 50.9
Total project cost for the nancing plan purposes = 122.5
Considerations in project evaluation 73
at 20, 40 and 40 per cent spread over three years starting one year after the cost
estimation date. Price contingency is equal to ination at 5 per cent annually. Physical
contingency is 10 per cent and the discount rate is 12 per cent. Commissioning date
is after three years. The nancing plan requirements are in Table 6.1.
The project cost in the money of the base year is equal to the base cost plus the
physical contingency (i.e. 100 + 10). The project cost at the commissioning date
is the base cost plus the physical contingency, compounded by a factor of 1.626,
i.e. (1.12 1.05)
, where (1.12 1.05) is nominal discount rate. Therefore,
project cost at the base (planning year) = 110 (money of the base year),
project cost at the commissioning year = 178.86 (money of the commissioning
project nancing requirements = 122.50 (plus interest during construction and
working capital if any).
This is elaborated further in Section 6.2.
6.2 Interest during construction
An important consideration in project evaluation is how to account for interest during
construction. In calculating the IRR of the project, the project cost can be considered
to be equal to a single evaluated cost at the base year. If this is done, then it is not
necessary to account for ination or interest during construction in calculating the
IRR. If the base year is the project execution commencement year, then the project
cost at that year is the estimated cost of the project in the money of that year plus
the physical contingency. If the project is costed in the money of the commissioning
year, then the price contingency is added to the cost stream of payments for project
execution, soas torender it inthe moneyof the respective price contingencyyear. Then
this stream is discounted (compounded) to the commissioning year by the nominal
discount (compounding) factor, as already explained in Section 6.1. Usually, the
nominal discount rate is not much higher than the interest rate utilised for nancing
construction (interest during construction). The combined price contingency and the
discount (compound) rate account for the interest during construction, where the latter
is ignored in evaluation.
Therefore, for nancial and economical evaluation of projects, the project capital
costs can be presented as a lump sum either in the money of the project planning
year (commencement of execution) or the project commissioning (completion) of
execution year. The latter gure is obtained by compounding the actual annual dis-
bursements on the project to the commissioning year through the nominal discount
rate. Alternatively, the project cost, while estimated in the planning year, can be pre-
sented as streamof payments along the execution period. In this case the physical and
price contingencies are added and this stream is discounted by the nominal discount
rate to the base year, whether it is the year of planning or commissioning.
Therefore, interest during construction is not directly considered in the nancial
and economical evaluation. It is ignored if the above procedures are carried out
74 Economic evaluation of projects in the electricity supply industry
correctly. However, interest during construction is important for planning the nance
of the project. It has to be realised that if the project is nanced entirely by equity,
then there will be no payments for interest during construction.
6.3 Sunk costs
Sunk costs are dened as those costs that have been incurred on the project, before
commencing the present evaluation. Despite their value to the project, they have
already been spent. Therefore, they are not included in the costs of the project for
newdecision making or for determining whether to proceed with the project or not [2].
An investment is sunk if the asset cannot easily be used for any purpose other than
its original purpose. Sunk costs can be different from xed costs of a project. For
instance, an investment in a power station building is sunk because the building has
no other use (without great cost and difculty). On the other hand, an investment in
building management ofces for a project in the city (although it is a xed cost) is
not a sunk cost, since such an asset can be readily converted for other purposes [3].
When evaluating the costs and benets of completing or extending a project, the
costs and benets that already exist are not included in the evaluation. It is only the
expected future costs and benets that matter in the decision making today. Therefore,
the IRRof completing unnished projects or extending existing projects would appear
to be very high, but that reects the nature of the decision being made.
So if it is decided to convert or extend an existing installation or to utilise an exist-
ing infrastructure, there is no need to include past investments in the new evaluation.
These are sunk costs, which should not be considered. However, it may be appro-
priate sometimes to calculate the returns on the total project (including sunk costs)
to evaluate earlier decisions and learn of such experiences. This, however, need not
interfere with the present evaluation decision making.
Sunk costs occur frequently in the electricity supply industry, for example in a
decision to extend or refurbish an existing power station or substation site, updating
an existing transmission line, converting an existing dam into a hydro-power facility,
etc. In all such cases, it is only the added costs and benets of the project that need
consideration. In evaluating the original project, the prospects of future extensions and
modications are contemplated. Such prospects should be included in the evaluation
of the original project, since the success of the original project evaluation may be
contingent on such future prospects.
6.4 Depreciation and interest charges
In evaluation, the cost and benet streams of the project are reduced to cash ows.
As already dened, cash ows are the difference between pounds received and spent
out. Therefore, in calculating the internal rate of return, depreciation and interest
charges are ignored. Depreciation does not represent actual cash owand correspond-
ingly is not involved in present valuing or any other economic evaluation criteria.
Considerations in project evaluation 75
Depreciation is, however, important in the preparation of nancial statements (nan-
cial projections) of private utilities and rms. It inuences the taxation, the prot/loss
statement, and hence dividends to shareholders.
With regard to the interest charges, it must be remembered that the IRR is the
maximum rate of interest that could be paid for the funds employed over the life of
the investment without loss to the project. Therefore, interest charges also should be
excluded fromcalculating the rate of return of the project and other evaluation criteria
[3,4]. This equally applies to interest during construction.
In most projects, nancing is done by a combination of equity and loans.
The investor is interested to know the IRR of the project and the return on equity.
In calculating the return on the equity, the amount of loan servicing (interest on the
loan and loan repayments) has to appear as cash expenses and deducted in the appro-
priate years from the current income stream. Simultaneously, the amount of loan has
to be deducted from the project cost. Thus, the costs, benets and net benets will
represent those accruing to the equity only. The IRR calculated will be the rate of
return on the equity. It has to be compared with the opportunity cost of the capital,
i.e. the return that this equity capital can obtain in the best alternative investment. The
investor would undertake the project only if the internal rate of return on the equity
in this project is higher than the opportunity cost.
6.5 Financial projections
It is useful to carry out nancial projections for a new project. Such nancial
projections help in calculating the cost and benet streams and consequently com-
puting the projects IRR. The nancial projections [5] necessary are: (a) projected
income statement, (b) projected balance sheet and (c) ow of funds statement. The
income statement is useful in project evaluation, since it contains most of the infor-
mation needed for the nancial and economical evaluation. The income statement
(in nominal terms) would detail for each year the income of sales and services, the
cost of products (xed plus operation), maintenance and capital charges (depreciation
and interest). The information will allow the calculation of the prots in any given
year and, after deduction of taxes, the calculation of net prots for distribution to the
equity owners.
The nancial statement is produced in real terms; usually in the gures of the
base year. It is more appropriate to plan the nancial projections in current (nominal)
terms to ensure coverage of full capital costs by the nance plan. It is also appropriate
to evaluate the nancial development of the rm and the viability of the project under
the realistic situation of ination. Therefore, the real nancial projections (of the base
year costs and revenues) are inated, year by year, with a gure normally equal to
the expected ination rate. This will result in nancial projections in current (nom-
inal) terms. Such current projections will enable one to ascertain that the nancing
available in the formof equity, loans, nancial allocations (depreciation) and retained
prots will be sufcient to meet nancial requirements of the project in current terms,
year by year.
76 Economic evaluation of projects in the electricity supply industry
A single ination rate may be useful for the estimation of nancial statements.
In some cases, and as already mentioned, certain items of costs and benets may
deviate from the expected general ination level. For instance, expected increases in
fuel prices may be higher than the ination rate. Also, electricity price increases may
display a trend of being slightly lower than the general price increase. In such cases,
ination differentials should be included in drawing out the nancial statement to
allow more realistic assessment of future trends. Such ination differentials are also
important when drawing out the cost and benet streams in real terms for calculating
the projects IRR. For instance, if it is expected that fuel prices, in the future, will
increase at y per cent annually over the general ination rate, then the real outlay for
fuel in the cost stream should increase at a compound rate of y per cent annually over
the base year.
The income statement, in current terms, aids in calculating the tax on prots. Most
private investors are interested in the after-tax nancial rate of return. Therefore, the
income statement will allow the compilation of tax for each year. This is deducted
from the net benet stream to allow computation of the after-tax nancial rate of
return. Also, in the case of existence of loans, the deduction of the loan component
and loan servicing from the benet stream will enable the calculation of the after-tax
nancial rate of return on equity.
It is, however, essential to understand the concepts of nancial statements: income
statement, balance sheet and funds ow statement, in order to assess the actual per-
formance of the company (rm) in the commercial market and the prots that will be
paid to shareholders. It was explained in Section 5.4 that such nancial statements
(commercial accounts) are not criteria for proper project evaluation or least-cost solu-
tion. However, preparation of pro forma nancial statements and nancial projections
help not only in computing the cost and benet streams and consequently the IRRand
NPV, they also project the nancial and commercial protability of the project and
the actual nancial return that is likely to be paid to owners and share holders. In case
of projects, analysing nancial performance and the calculation of nancial ratios is
useful fully to grasp the envisaged performance of the rm, and impact of the project
on its nancial performance and protability to owners, the nancial problems the
rm is likely to face (availability of funds, debt servicing, liquidity problems, etc.) as
well as to undertake comparisons of the rms performance with market acceptable
nancial ratios. Such nancial performance and nancial ratios will affect the ability
of the rm to raise funds in the money market and the terms of these, as well as the
price of the rms share if these are traded in the stock exchange. Sections
offer short explanations of nancial statements and ratios.
6.5.1 Financial performance and nancial statements
Typical nancial statements [6,7] will look like those of Table 6.2, which contains
an income statement followed by a balance sheet. These are summary nancial state-
ments. Annual reports of companies will show these summary nancial statements
as well as notes that explain, in detailed tables, each of the items that appear in the
summary nancial statements, including a table for allocation of prots (if any) which
Considerations in project evaluation 77
Table 6.2 Summary pro forma nancial statement
for a power generating company (gures
are only indicative and in million)
2002 2003
Income statement
Income of electricity sales 125.0 128.8
Other income 2.0 2.7
Costs of generation (other than fuel) 18.0 18.5
Fuel costs 50.0 52.0
Other expenses 8.0 7.0
Depreciation 25.0 25.0
Earning before interest and tax (EBIT) 26.0 29.0
Net interest 10.0 9.0
Tax at 40% 6.4 8.0
Net income 9.6 11.7
Preferred stock dividend (if any)
Earnings of the common stock 9.6 12.0
Balance sheet
Cash and short-term securities 5.5 5.0
Receivables 20.0 21.0
Inventories 15.0 16.0
Other current assets 2.5 2.5
Total current assets 43.0 44.5
Land, plant and equipment 554.0 544.0
Other long-term assets 20.0 40.0
Total assets 617.0 628.5
Debt due 10.0 10.0
Payables 100.0 95.0
Other current liabilities 5.0 5.0
Total current liabilities 115.0 110.0
Long-term debt 100.0 90.0
Other long-term liabilities 102.0 118.9
Preferred stock (if any)
Shareholders equity 300.0 309.6
Total liabilities 617.0 628.5
explains how prots applicable to common stock will be divided between dividends,
reserves and retained prots.
The income statement of Table 6.2 can be a pro forma income statement for a
power-generating rmthat is supposed to commence its full production early in 2002;
the gures of 2003 are also pro forma gures based on same energy sales, with a
higher income of 3 per cent, which is the general ination index expected for that
78 Economic evaluation of projects in the electricity supply industry
year. However, prices of fuel have been inated by 4 per cent in accordance with
agreements and general price trend for fuels.
In the income statement, the income fromelectricity sales as well as other income
(which can be from selling services or income from other investments) represents the
total income of the rm. From this, costs are deducted; these are costs of operation
(salaries, consumables, etc.) as well as fuel cost and other expenses (rents, rates,
etc.). The allocations for depreciation are also deducted. The result is earnings before
interest and tax (EBIT). After deducting interest the taxable income remains. The net
income of the rmis the EBITless the amount of interest and tax. Earnings applicable
to the common stock (or to private investors) are the net income less dividends to the
preferred stock (if there are any preferred stock which do not exist in the case of
Table 6.2).
The balance sheet is a snapshot of the rms assets and liabilities at the end of the
year. These are usually listed in declining order of liquidity. Usually assets are current
assets and long-term assets. Current assets are cash and short-term securities that can
be easily liquidated, as well as receivables (which are the electricity bills that have not
been paid yet), inventories of fuel, spare parts and other materials and consumables.
Long-term assets consist mainly of the stock of generating plant, land, buildings, fuel
storage, ofces and similar facilities. The balance sheet shows the current value of
these assets only in the rst year. In later years this value is reduced by the amount of
annual depreciation. Also, new assets can be added. Therefore future balance sheets
do not show the current or actual market values of assets, or their replacement values,
but rather show their depreciated value for nancial statement purposes.
Liabilities of the rm are also current and long term. Current liabilities are pay-
ments that the rm will have to pay in the near future (interest payable by the rm
as well as debts due in the next year). Bonds, long-term loans and similar nancial
instruments that will not be paid for many years are the long-term liabilities. After
deducting all short- and long-terms liabilities, what is left is the shareholders equity.
This equity is equal to common stock plus retained prots. The shareholders equity,
its annual growth and its comparisons with the shareholders paid-up capital, are
important indication of the nancial viability of the rm.
Most rms have to expand in the future. They can do that by self-nancing, issuing
new common stock or preferred stock, or by loans. Self-nancing is very important
for a rms healthy growth. It is equal to retained prots and reserves plus depreciation
6.5.2 Financial ratios
Financial ratios are used to understand and test the viability of a rm, the performance
and returns of its investments. In case of evaluation of individual projects, nancial
ratios greatly help in studying the impact of the new project on the nancial and
commercial outlook of the rm (see Section 6.9). There are many nancial ratios of
interest, the most important of which are briey stated below.
Debt-equity ratio is a measure of the leverage of the rm
long-term debt +value of any leases
Considerations in project evaluation 79
In the case of Table 6.2 it equals 100/300 = 0.33 (for the year 1998).
Times interest earned ratio demonstrates the ability of the rm to serve the
interest on its debt
EBIT +depreciation
Referring to Table 6.2 it equals
(26.0 +25)/10 = 5.1.
Current ratio is a measure of the rms potential reservoir of cash and its ability
to meet its short term liabilities
current assets
current liabilities
Current ratio in Table 6.2 is 43.0/115.0 = 0.374.
Net prot margin is the proportion of sales that nds it way into prots
EBIT tax
From Table 6.2 it equals (26.0 6.4)/125 = 0.157.
Return on total assets and return on equity are most important indicators of a
rms performance.
Return on total assets =
EBIT tax
average total assets
In Table 6.2
= (26.0 6.4)/610 = 0.032
(average total assets equal sum of assets at the beginning and end of year divided by
two and assumed to equal 610 m for year 2002).
Return on equity =
earnings available to shareholders (owners)
average equity
this equals
9.6/300 = 0.032.
Priceearnings ratio (P/E ratio) is a much quoted measure by the nancial press.
It is the ratio of the price of a rms share in the stock exchange compared with
its earnings. Therefore it estimates how the rm is esteemed by investors and their
expectation of its future performance.
P/E ratio =
stock (share) price
earnings per share
In the case of Table 6.2, if the number of shares of the rm is 300 million and the
price of a share in the market is 1.05 then the earnings per share are 0.032 and the
P/E = 33.
80 Economic evaluation of projects in the electricity supply industry
A high P/E ratio (like above) can indicate that the rm is at low risk, or there is
expectation of higher growth in earnings in the future or in the value of the stock (or a
combination of these).
Dividend yield =
dividend per share
stock price
In the case of Table 6.2 this equals
0.032/1.05 = 0.0305

= 3.1 per cent.

6.5.3 Flow of the funds statement sources and applications of funds
This important nancial statement shows how the rm utilises its current assets to
fund its investment and distribute dividends to its shareholders.
Internal sources of funds for a rm are operating cash ow income (after tax and
interest), plus depreciation. External sources were explained before. Applications
(uses) of funds are utilised for nancing new investments, paying dividends as well
as increase (decrease) in the networking capital.
Table 6.3 explains a Sources and Applications of Fund Statement, as applied to a
rm having the following income statement.
Table 6.3 Sources and Applications (uses)
of Fund Statement
Income Statement
Income 2000
Cost of sales 1400
Depreciation 100
EBIT 500
Interest 100
Tax at 40% 160
Net income 240
Sources and Applications of Funds
Net income 240
Depreciation 100
Borrowing 400
Stock issue 400
Sources 1140
Applications (uses)
New investment 1000
Dividends 100
Increase in networking capital 40
Applications (uses) 1140
Considerations in project evaluation 81
Such a Sources and Applications of Funds Statement leads, with the information
available fromthe same years nancial statement and the other market and investment
data referred to above, into a pro forma nancial statement for the next year.
Financial planning that necessitates attempts to predict the rms nancial per-
formance involves simulation and many assumptions including prediction of sales,
prices, performance of competitors, price of money, depreciation and taxation polices,
etc. Such planning has to proceed year after year with the approach followed in
Tables 6.2 and 6.3. A manual approach is tedious. Nowadays, standard spread-sheet
programs such as LOTUS 1-2-3, EXCEL 7 and more recent versions greatly ease the
work of nancial planning managers.
6.6 Evaluation of benets in the electricity supply industry
Electricity production has one output, that is electrical energy in the form of kilowatt
hours (kWh). The benets of most investments in the industry can be presented in
the form of kWh. In selecting the least-cost solution projects, it is wiser to present
these benets in the form of kWh rather than money; then discount these benets [7].
Benets inmonetaryterms are kWhmultipliedbythe tariff, or other forms of valuation
of the kWh (as in the case of reducing electricity interruption). Dealing with kWh
will ease the work of the evaluator by avoiding other estimations like tariffs. This
has been shown by Table 5.2. However, the following will deal with it in greater
This approach is particularly suitable for evaluating base load generation alternat-
ives. The real costs of each alternative (capital plus operation) are discounted to the
base year and divided by the discounted net benets (which are the generated kWh
during the project lifetime discounted to the base year). The least-cost solution is
the alternative with the least discounted real cost per discounted kWh. Such methods
have the advantage of being independent from tariff evaluation and ination.
Such an approach does not take into account system effects; the contribution
of each base load variant (nuclear compared with coal, for instance) must take
into consideration its system effect. Nuclear have a much higher investment cost
over CCGT per kW installed. Its higher utilisation factor would save some uneco-
nomical generation, which enhances its attractiveness. This is possible to compute
through generation simulation, and assessing the impact of each alternative on the
overall generation cost. This is detailed in Section 6.8. In addition, not every kWh
in the electricity supply industry is measured by the same yardstick. The value of
a base generation kWh is different from that of peak generation. A kWh curtailed
has a much higher value than the tariff. The same applies to the network. Build-
ing a parallel transmission line will increase load transfer capability and reduce
system losses, which have a value reected in the tariff. It can greatly improve
supply continuity which would reduce the amount of electrical energy curtailment,
where each kWh saved will have an economical value of multiple that of the
82 Economic evaluation of projects in the electricity supply industry
In short, for alternative projects in the ESI, the procedure of evaluating the benets
in terms of discounted kWhs to the base year is quite a useful tool. However, it is only
accurate if the system effects of each alternative are the same or if different system
effects are evaluated and incorporated in the analysis.
6.7 Timing of projects
There is usually great pressure to start publicly owned projects as soon as possible.
However, a project should not be started unless the evaluator is certain that the project
will have a positive net present value, while utilising the opportunity cost of capital
as a discount rate. Even then, it may not be the optimum time to start the project.
Assessing the effect of delaying the project has to be undertaken to evaluate whether a
possible net present value will be better slightly into the future. If a future net present
value is possible, then the project has to be executed at the year that provides the
highest net present value.
Usually, a project should be executed when the rst year net benets exceed
opportunity cost of the investment, i.e. the discount rate times the project cost. If the
delay causes a rise in the cost of the project, in real terms, this should be taken into
6.8 Dealing with projects with different lives and
construction periods
Project alternatives may have different lives and execution periods [8,9]. The effect of
the length of execution period is effectively reected by discounting to the base year.
The base year can be the project evaluation year, or the project commissioning year,
with the same conclusions. For alternatives with widely different execution times
(combined-cycle gas-turbine plant with typically two years for execution compared
with four years for nuclear) system effects have to be considered.
There are various ways for comparing projects with different lives. If we compare
a coal plant with an expected life of 40 years with a CCGT alternative with 20 years,
then we repeat the investment cost of a new CCGT and add it to the cost stream at
20 years. However, things are not that simple when the expected life of the coal plant
is only 30 years. In this case, we have to consider adding an investment in the form
of a new ctitious plant (P
) with a considered cost of 10 years after the end of the
20 years life of the rst CCGT plant. Since the comparison is over 30 years only, we
have to calculate the cost of this new plant P
(which will actually live for 20 years)
over only its rst 10 years of service. This cost will be equal to the benets (over the
period 2030 years) at a discount rate that is equal to the internal rate of return (IRR)
of this investment. Since we know the cost of plant P
and can evaluate its benets
over its full life, we can calculate its IRR. This IRR is utilised as a discount rate of
the benets over the remaining 10 years of the project life (the period 2030 years).
It will be equal to cost of the ctitious plant P
that will (for comparison purposes)
Considerations in project evaluation 83
serve only over the period of 2030 years. This evaluated cost of P
will be added to
the cost stream after 20 years.
Discounting greatly reduces the signicance of this problem, particularly if high
discount rates are concerned. After 20 years, the discounted value of the repeat project
is 0.149 of its present cost at 10 per cent discount rate, and only 0.061 at 15 per cent
discount rate.
The annual cost method as well as the accepted method, UNIPEDE, manages the
life of the alternative throughcalculatingthe discountedcost per discountedkWh. This
method, also, does not reect the technology advantage of the shorter life alternative.
6.9 Expansion projects
For a project expansion (or a rms activity), it is necessary to carry out a with and
without project evaluation. This involves estimating the additional benets brought
about by the project and comparing them with the additional costs caused by the
project. With and without project evaluation is quite common in the electricity supply
In this case, the analysis is slightly more complex. It is necessary to produce
two sets of nancial statements over the life of the project: one including the project
expansion and another without it. The difference between the two statements indicates
the incremental nancial benets brought about by the project expansion. Such incre-
mental nancial statements allow the calculation of the incremental nancial IRR.
After allowing for ination, the determining factor for proceeding with the project
expansion will be the incremental real IRR.
This is different from before and after comparison, because even without the
project expansion the net benet in the project area may change.
6.10 System linkages
System linkages are important in electrical power systems and were referred to more
than once earlier. However, these need to be handled in more detail. The electrical
power industry, more than any other industry, has the distinct peculiarity that most
of its major projects have nancial and economical impacts that extend beyond the
connes of the project to affect the whole electrical power system. This is because
of the interconnected system and synchronic performance. Any new major project,
or action, will have an immediate impact that is reected on the economics of the
supply, and sometimes on its quality. Building a new modern and efcient power
station would contribute to more electrical energy production and reduce the overall
system costs. This is through the production reduction from costlier power stations.
Halting a generating unit for maintenance can cause (beside the maintenance cost)
major system costs, through the need to operate or increase the production of a
less economical generation plant. Adding a new transformer or transmission line can,
besides enhancing the transfer of power, reduce systemlosses and increase availability
84 Economic evaluation of projects in the electricity supply industry
of supply. This, in turn, will reduce the economic and social cost to the consumers of
electricity interruptions.
Therefore, in all major power projects, particularly generation, it is advisable to
perform a computer simulation over the next few years, with and without the project.
The simulation output of the project is integrated in the system performance. This
will allow a better evaluation of the nancial and economical impacts of the project.
Details of the system simulation are fully explained in published literature [10] and
will also be covered in Chapter 10. A ow chart of generation costing and expansion
simulation is depicted in Figure 6.1.
Many projects in the electricity supply industry are undertaken to reduce supply
interruption and improve service to consumers. In these instances, it is necessary for
read: load data
existing sets and
future set details
write: costs of expansion,
list future set sizes,
and commissioning dates of
different schemes
least-cost solution
calculate percentage energy loss
index (PEL)
compute operation and costs
for period n (year y)
no. of sets
J =J +1
J =list of existing system and new sets
n =N
y =Y
sum annual operation and
costs for year y
y =study period in years
calculate PV of (investment
in new sets in year y +
cost of generation year y)
y =y +1
increase values of
load by one year
Figure 6.1 Costing of a system expansion plan
Considerations in project evaluation 85
the electrical utility to put a monetary value on each kWh curtailed. The economics of
the network strengthening projects are evaluated through comparing the discounted
annual value of the reduction in electricity curtailment (annual kWh saved multiplied
by the social cost of each kWh interrupted) with the annual cost. This will be dealt
with in detail in Chapter 10.
6.11 References
economic rates of return for DFCprojects (International Bank for Reconstruction
and Development, Washington DC, 1984)
2 SQUIRE, L., and VAN DER TAK, H.: Economic analysis projects (The Johns
Hopkins University Press, 1989)
3 FELDER, F.: Integrating nancial theory and methods in electricity resource
planning, Energy Policy, February 1996, 44, (2)
4 RAY, A.: Cost benet analysis (The Johns Hopkins University Press, 1990)
5 BREALY, R., and MYERS, S.: Principles of corporate nance (McGraw-Hill
Inc, 2002)
6 BRIGHAME, E.: Fundamentals of nancial management (The Dryden Press,
1989, 5th edn.)
7 Projects and costs of generating electricity (OECD, Paris, 1989)
8 MORRIS, T. E.: Economic comparisons in planning for electricity supply, Proc.
IEE, March 1970, 117, (3)
9 DAVISE, B. G. (Ed.): The economic evaluation of projects (The World Bank,
10 KHATIB, H.: Economics of reliability in electrical power systems (Technicopy,
Glos, 1978)
Chapter 7
Economic evaluation of projects
7.1 Introduction
The nancial evaluation of a project studies its performance and return (protability)
from the points of view of the industry (the utility and the rm), the owner and the
investor. Economic evaluation, on the other hand, studies project benets and returns
from the national economy point of view and assesses the effect the project will
have on the overall economy of the country. While small projects have limited, if
any, impact on the national economy, large projects have social and environmental
effects, which cannot be ignored (referred to earlier as externalities). The electrical
power industry is highly capital intensive. A modern power station normally costs
hundreds of millions of pounds, and so do some network projects. In high-capital
projects of this nature it is necessary to nd the least-cost solution not only from
the point of view of the industry but from that of the national economy as well. The
project evaluation should not be restricted to its protability and should also evaluate
its national economic and environmental impacts (social impacts) and compare them
with those of other competing projects in the resource-limited national economy to
ensure economic efciency.
Economical analysis of major projects, therefore, evaluates two things:
(1) the priority of the project in the national plans of the country and
(2) its effect on the overall economy of the country.
The ultimate purpose of the analysis would be to provide a measure of the impact of
the project on the national welfare as exemplied by increased consumption of goods
and services (including electrical energy) that serve as a proxy to increased welfare.
Economic efciency is important to society and has four primary components.
The rst component is the requirement of production efciency, or incurring the
minimumfeasible cost in producing goods and services sold. Second, efcient variety
is needed, meaning that the menu of goods and services offered is tailored to the wants
and needs of customers. Third, society wants allocative efciency, where the goods
and services go to customers who value these goods and services most highly. Finally,
88 Economic evaluation of projects in the electricity supply industry
society wants dynamic efciency, which means that the rst three types of efciency
are sustained [1].
In the electricity supply industry the rst component is fullled through the least-
cost solution alternative. The second and third purposes are achieved through the
implementation of appropriate electricity tariff and security levels to different classes
of consumers. The last purpose of sustainabilityis attainedthroughintegratedresource
Economic efciency (which takes into consideration social as well as environ-
mental costs and benets) should be a fundamental criterion of public investment
and policy making. It should also be fundamental for large capital-intensive private
sector investment that replaces, supplements or competes with public investment.
This includes investments made by independent power producers. If real costs and
benets of large projects are not addressed from the perspectives both of the industry
and of the whole economy the wrong projects (or alternatives) may be selected.
The same method of discounting costs and benets is used for both nancial and
economic evaluation. Economic evaluationis concernedwithestimatingthe economic
rate of return (ERR). Financial analysis, on the other hand, evaluates the internal rate
of return (IRR) and considers only nancial parameters in the analysis. A project,
for example building a power station ring cheap low-quality coal and located near
the load centre, may have a high nancial IRR. But when environmental costs of the
project are considered they may result in low (or negative) ERR and may lead to the
rejection of the project on economic rather than nancial grounds [2].
In many cases market prices do not reect the real cost of resources, products or
services to the economy. Market prices are usually distorted by duties, taxes, subsidies
and other trade restrictions. Such instruments have a major inuence on the nancial
protability of a project from the industry or investors point of view but none on its
economic viability from the perspective of the national economy. Distortions, par-
ticularly subsidies, vary from one country to another but are more prominent in the
developing countries than in market economies where efcient and transparent prices
prevail. They do exist in every country in varying degrees, particularly in energy fuels
and products prices. This is most vividly exemplied in the electrical power industry
where in most countries prices of fuels are set at a level far from their true cost to the
A lot of work has already been done during the past three decades to establish
the techniques for economic evaluation of projects. Most of this work was done by
the international lending agencies like the World Bank, OECD, ODA and various
United Nations agencies [37]. Handling detailed mechanics of economic evaluation
requires a skilled economist. These are briey explained below. An important issue,
which project planners need to be aware of, is the existence of distortions and the
general techniques of dealing with them. Four issues are important: transfer payments,
border and shadow pricing, externalities, and system linkages. Two other related
issues are also important: integrated resource planning (this was dealt with briey
in Chapter 1) and environmental issues. The environmental impact of the electricity
supply industry is signicant. This is an externality that needs thorough evaluation
and understanding and is dealt with separately in Chapters 8 and 9.
Economic evaluation of projects 89
In most of the analysis that follows it is assumed that the ofcial exchange rate of
currency is not articially xed (overvalued) but rather is freely adjustable according
to international trading links. This is the case in all OECD countries and is becoming
increasingly so in most developing countries.
7.2 From nancial evaluation to economic evaluation
The two time streams of nancial costs and benets form the starting point for eco-
nomic evaluation. These nancial streams have to be adjusted and modied with
regard to the concepts of transfer payments, border and shadow pricing, and external-
ities. The essence of sound economic evaluation is to remove distortions, particularly
price distortions, to improve investment decisions. Such distortions are mainly caused
by transfer payments (subsidies, taxes and levies), imperfections in the domestic
market (monopolies, restrictive practices, etc.) anddistortions causedbytrade policies
(exchange rates, quotas, etc.).
Toshift fromnancial toeconomic evaluationit is essential toimplement a number
of steps:
(a) remove direct transfer payments,
(b) use border prices in the case of traded goods and services (particularly fuels),
(c) use shadow prices, particularly in dealing with non-traded items (such as land,
unskilled labour, etc.),
(d) account for externalities (especially environmental impacts and costs), and
(e) allow for the difference between accounting and the ofcial price of foreign
exchange, if any.
Therefore, in economic evaluation, transfer payments (taxes, duties, subsidies) are
not included. Costs and benets are priced in border (international) prices for traded
goods and shadow prices for non-traded goods. Externalities, whenever they exist,
are added to costs and benets.
7.3 Transfer payments
A transfer payment is a payment made without receiving any good or direct service
in return. In economic evaluation of projects the most-encountered transfer payments
are taxes and direct subsidies, as well as loans and debt service (payment of interest
and repayment of principal). These are treated as transfer payments because the loan
terms only divide the claims to goods and services between borrowers and lenders
and do not affect the total amount of true return to investment. Transfer payments
represent only shifts in claims to goods and services and not use of new production.
Theydonot increase or reduce national income andare hence omittedwhenconverting
nancial streams used in nancial evaluation to economic values used in economic
evaluation [8].
In the electricity supply industry, transfer payments normally apply to local duties,
fuel subsidies (or taxes) and other subsidies, taxes and interest. Such payments do
90 Economic evaluation of projects in the electricity supply industry
not represent direct claims on the countrys resources but merely reect a transfer of
control over resource allocations from one part or sector of the national economy to
another, and should therefore be omitted from economic evaluation. In contrast, they
are quite important in nancial analysis.
Economic analysis is not concerned with sources of investment funds (equity or
loans or a combination of these) and repayment of loans (particularly local loans),
since similarly the loan and its repayment are nancial transfers and are not part of
the economic analysis. The economic cost of a project is its investment cost in the
base year less its discounted terminal value if any, converted into economic terms as
detailed below. It is, however, essential to distinguish between taxes that are transfer
payments and are ignored in economic analysis, and other taxes that are a payment for
goods and services and should be included. For instance, a road tax can be a payment
for the services provided by the road, and a municipality tax can involve a charge for
sewerage and should therefore be included in the analysis.
Subsidies are direct transfer payments that ow in the opposite direction from
taxes. Fuel subsidies are common in the electricity supply industry, particularly
for local coal supplies. Conversely, imported sources of fuel may be heavily taxed
to encourage local energy sources, possibly for environmental reasons, or merely to
provide an income for the government. In such cases local energy sources have to
be priced at their full actual cost to the economy. If these items are tradable (as will
be explained below) then their set prices should reect border prices if they are higher
than their production cost.
The same logic applies to credit transactions loans and loan servicing. Such
transactions do not increase national income but again represent the transfer of control
of resources fromone sector of the economy to another, i.e. they are transfer payments.
Foreign loans that impose a burden on foreign reserves or that are subsidised by an
undervalued currency have to be considered in the economic evaluation.
7.4 Externalities
An externality is an effect of a project felt outside its connes and is not included
in its nancial evaluation. Externalities may be either technological or pecuniary.
An example of a technological externality might be pollution from a power station
that causes direct material and health damage. Economic evaluation usually tries to
incorporate technological externalities, especially costs, within the project account
and thus change them from externalities to project costs and benets (internalise
them). For example, costs of the damage to buildings and health by sulphur dioxide
) emissions, and to water basins caused by the waste discharges from the power
station, may be calculated and assigned to the project. Pecuniary externalities arise
when the project affects the prices paid or received by others outside the project,
for example, where building a new efcient and clean power station reduces prices
of electricity to users. Pecuniary externalities have to be included in both project
nancial and economic analysis.
Externalities are not easy to dene and are very difcult to quantify. Their
identication and attempt at quantication is an important part of the job of a skilled
Economic evaluation of projects 91
project evaluator. Some externalities are positive. In the electricity supply industry
they may be in the form of technology advancement, export promotion, job creation,
training, etc. Examples of negative externalities include detrimental environmental
impacts and congestion.
Most large projects in the electrical power industry have externalities, particu-
larly environmental impacts. These range from minor visual impact and landscaping
problems in small transmission and distribution projects to very serious pollution
problems, as in low-quality coal power stations. In most cases such environmental
aspects are identied in an impact assessment study and attempts are made to rectify
them in project design and costing. However, other intangible effects, like visual
impact, noise level, congestion, etc., are very difcult to quantify, as are some of
the benets like technological development, technology transfer and human capacity
building. Still they should not be ignored and every effort should be made to identify
and quantify them whenever possible. Externalities can have a strong inuence on
the choice of the least-cost solution, particularly when the difference in cost between
alternatives is small.
It is important to try to identify all externalities caused by the project. Where there
are signicant externalities an attempt should be made to quantify them and include
their values in the project costs and benets. Where it is difcult to quantify them,
as usually is the case, they should be cited in the project economical evaluation and
they may affect the choice of the least-cost solution. Environmental externalities of
electricity production are particularly important and these are dealt with in detail in
the following chapters.
A main externality aspect of a project in the electricity supply industry is the
system linkage of projects. System linkages are external to the project itself but are
internal to the electricity supply industry as a whole, and therefore cannot be treated
as a true externality. They should be taken into consideration in all nancial and
economic evaluation of projects.
7.5 Border and shadow pricing
During construction each project incorporates a lot of inputs (resources) such as
equipment, materials, land and manpower. During the lifetime of the project it also
consumes inputs, and produces output (product). Among the most important oper-
ational inputs in power projects are fuel, manpower and similar resources. In the
nancial evaluation these inputs are valued at their market prices. Market prices are
almost never ideal and are often distorted to varying degrees in different countries.
The industry and investors are mainly interested in market prices of inputs and outputs
because that is what they have to deal with and it is these prices that determine nancial
protability. Economic evaluation goes beyond this by investigating the true impact
of the project on the national welfare. To achieve this, prices of resources must be set
at their true cost to the economy [9].
Inputs and outputs can be classied into two categories: traded and non-traded.
A project input or output is deemed to be traded if its production or consumption
will affect a countrys level of imports or exports at the margin. A project input or
92 Economic evaluation of projects in the electricity supply industry
output is considered to be non-traded because of its bulkiness, cost consideration and
immobility or other restrictive trade practices. Machinery and equipment, as well
as fuel and skilled labour and marketable products, are considered tradable. Non-
traded goods and services include items like land, water, buildings, unskilled labour,
electricity (in most cases) and many other services and bulky material. Traded and
non-traded goods and services are part of project inputs and outputs. For economic
evaluation they have to be priced at their true cost to the economy.
7.5.1 Pricing traded inputs and outputs
Because they can be traded, i.e. imported as well as exported, tradable inputs and
outputs create a change in the countrys net import or net export position at the mar-
gin. They must be valued, in economic evaluation, at border prices. Border prices
are world prices, free on board (FOB) for exports and cost, insurance and freight
(CIF) landed cost for imports, adjusted by allowing for domestic transfer costs. Trans-
fer costs are costs that are incurred in moving inputs and outputs between project site,
border and target markets.
Take coal as an example. The border price of imported coal, which will be incorpo-
rated in the economic evaluation, will be the CIFprice at the nearest port plus handling
and transport charges to the generating plant. If this coal is produced locally, its eco-
nomic price will be its FOB price at the port of export minus the cost of transport
from the coalmine to the port plus the cost of transport to the generating plant. For
bulky materials, like coal, such transport prices are signicant and greatly favour
local production.
Consider an example in which coal can be imported by country y at $80 ton
with transport cost between country x and country y at $20 ton
. If country
x would export its production to country y then it has to price it at $60 ton
($80 $20 ton
). If the cost of handling this coal and transporting it to the export
port of country x is $15 ton
, then coal at the mine-mouth has to be $45 ton
If this coal will be used locally instead and with transport plus handling cost of
$5 ton
from the local mine to the local power station then the economic cost of
coal, will be $45 + $5, i.e. $50 ton
, irrespective of the actual cost of extraction,
which can be much less.
If the cost of production of coal in country x increases and it considers importing
outside coal from a source with a sea transport cost of $15 ton
, then its cost CIF of
imported coal will be $50 + $15 = $65 ton
. If transport of this coal to the power
station will involve another $8 ton
then the total cost of imported coal to the power
station will be $73 ton
Country x is advised to continue production of coal as long as its production cost
is equal to $68 ($73 $5 ton
local transport cost from mine to power station). If
country x decides to continue producing coal from its mines, even if its production
cost reaches $90 ton
, while selling it at $70 ton
to the power station, then its
coal subsidies will amount to $20 ton
. Such subsidies are excluded in the economic
evaluation. The market price for coal will be $70 ton
in the nancial evaluation of
the investors, and $73 ton
(i.e. the border price) in the case of economic evaluation.
Economic evaluation of projects 93
A decision to utilise a local resource (like coal) is not dependent only on produc-
tion costs and border prices but is also inuenced by many other political and social
considerations, like utilising local resources, creating local employment, supply secu-
rity and shortage of foreign exchange. In making such decisions, however, the border
price of coal has to be calculated and taken into consideration in evaluating plans and
7.5.2 Pricing non-traded inputs and services
Non-traded goods and services are priced at their shadow price. A lot of research was
done in understanding and evaluating shadow pricing [36]. With the enhancement
of free trade, freely convertible currencies and open markets, shadow pricing is still
required but not to the extent it was in the past.
In evaluating non-traded goods and services it is essential to differentiate between
non-traded tradables and non-tradables. Non-traded tradables are goods and services
that can be traded on the international market but are not because of their cost being
higher thaninternational prices (e.g. local lowqualitycoal), or because of trade restric-
tions and policies (quotas, restrictive import taxes at potential import markets, etc.).
A good example of a non-traded tradable is coal. If the international price of
coal is $50 and its transport to the power station involves an additional $23, a local
coalmine with a high production cost of $68 (which is above international prices
hence rendering its product a non-traded tradable) will continue production protected
by the high transport prices. In such cases the economic price of a non-traded tradable
commodity is the opportunity cost of the product, that is the price it can command in
the absence of the project.
Most power projects involve non-tradable inputs, mainly materials for civil works
and labour. Such inputs can be decomposed into its components. Large civil works
like a power station building contain tradable and non-tradable components. Tradable
inputs (cement, steel, etc.) can be priced in accordance with their border prices. Non-
tradable inputs (gravel, sand, stones, labour, etc.) have to be shadow priced through
utilising conversion factors [9]. The most widely used factor is the standard conversion
factor (SCF). This factor is the average ratio of border and domestic market prices
and is equal to
M +X
(M +T
) +(X T
where M = CIF value of imports, X = FOB price for exports, T
= all taxes
on imports, T
= all taxes on exports. Through applying this conversion factor by
multiplying it by the non-tradable inputs it is possible to reduce the impact of local
distortions. In a way the SCF is the ratio between an ofcial and a shadow exchange
rate. In developing countries it is usually less than unity, signifying that the local
currency is overvalued.
Consider a country with imports valued at 100 million currency units and exports
of 50 million units, import taxes of 20 million units and export taxes of zero. The SCF
94 Economic evaluation of projects in the electricity supply industry
is equal to 0.88 (which is (100 + 50) million divided by [(100 + 20) + (50 0)]
million). It is also usual to have a SCF equal to 1.0 for skilled labour and 0.5 for
unskilled labour.
An example is a power station building, which is priced in local currency as
shown in Table 7.1. The conversion factors for steel and cement were calculated using
border prices as shown. The economic cost of the power station building will be as
detailed in local currency. An estimation of economic costs and benets is given in
Table 7.2.
Table 7.1 Conversion of nancial cost of a power station civil work
component into economic cost (in local currency units)
Component Financial cost Conversion factor Economic cost
Traded items
Cement 10 000 0.90 9000
Steel 30 000 0.80 24 000
Non-traded items
Other building materials 10 000 0.88 8800
Overhead 20 000 0.88 17 600
Unskilled labour 25 000 0.50 12 500
Skilled labour 5000 1.00 5000
Total 100 000 0.77 76 900
Table 7.2 Estimation of economic costs and benets [9]
Project inputs
A Net imports of tradable items (CIF plus converted port-to-project costs)
B Diverted net exports of tradable items (FOB minus converted source-to-port plus
converted source-to-project costs)
C Non-traded items
1 Land (converted opportunity cost)
2 Labour
(a) Skilled (market wage rate)
(b) Unskilled (converted shadow wage rate)
3 Goods (converted domestic market price plus converted source-to-project costs)
Project outputs
A Net exports (FOB minus converted project-to-port costs)
B Import substitutes (CIF plus converted port-to-market costs and minus converted
project-to-market costs)
C Non-traded items (converted factory-gate price)
Economic evaluation of projects 95
7.6 References
1 FEDLER, F.: Integrating nancial theory and methods in electricity resource
planning, Energy Policy, February 1996, 24, (2)
February 1996, 10, (1)
3 SQUIRE, L., and VANDERTAK, H.: Economic analysis of projects (The Johns
Hopkins University Press, 1989)
4 RAY, A.: Cost-benet analysis (The Johns Hopkins University Press, 1990)
5 LAL, D.: Methods of project analysis (International Bank for Reconstruction
and Development, Washington DC, 1976)
6 LITTLE, I. M. D., and MIRRLFES, J. A.: Project appraisal and planning for
developing countries (Heinemann Educational Books, 1974)
7 Appraisal of projects in developing countries ODA (Overseas Development
Administration), (HMSO, 1988, 3rd edn.)
8 GITTNER, J. P.: Economic analysis of agricultural projects (The Johns Hopkins
University Press, 1982, 2nd edn.)
9 CHRISTIAN, D. J., and PRASAD, R.: Guidelines for calculating nancial and
economic rates of return for DFCprojects (International Bank for Reconstruction
and Development, Washington DC, 1984)
Chapter 8
Environmental considerations and
cost estimation in project evaluation
8.1 Introduction
Electricity utilisation is environmentally benign and as a form of energy carrier
electricity is clean and safe. It causes no pollution or environmental emissions at
the point of use. It was also proven that electricity can be more efcient than other
forms of energy [1]. Therefore substituting electricity for other forms of energy can
greatly help in reducing global emissions and pollution caused by the use of the latter.
In addition, the fact that electricity production is undertaken at a single point, namely
the power station site, means that environmental problems associated with electricity
production are concentrated at a single point, which makes containing and dealing
with them much easier.
Electricity production can cause local and regional environmental impact and
may also have long-lasting detrimental global consequences. Some of these impacts
like the emissions of sulphur dioxide (SO
), nitrogen oxides (NO
) and solid par-
ticulates, which all have detrimental air quality implications, can be controlled by
investing in technology and abatement facilities. These measures can control and
reduce signicantly such emissions. Carbon dioxide (CO
), which is the main gas
suspected of causing global warming (greenhouse effect), is far more difcult and
expensive to control. More than half of thermal generation and 39 per cent of total
electricity production uses coal (sometimes low-quality coal and lignite). Coal use for
this purpose is increasing particularly in developing countries [2]. These countries,
with their limited nancial resources, cannot afford to invest in expensive measures
for environmental preservation, particularly those concerned with long-term global
effects. Their main concern is the production of the largest possible quantity of elec-
tricity to meet growing local demand in the most extensive manner and as cheaply as
possible. Their environmental actions, in most cases, are a response to an impending
major environmental disaster [3].
98 Economic evaluation of projects in the electricity supply industry
Employment of abatement technologies is not the only way to control emissions.
Substantial emission containment can be achieved through enhancing efciency in
production, conservation of use, the use of cleaner fuels (natural gas) and clean
technologies (as detailed later), and through the use of non-fossil energy sources
(hydro, nuclear and renewables). The major effort that has taken place recently in the
eld of improving efciency of electricity generation was discussed in Chapter 1.
Developments in this eld are still taking shape and will ultimately lead to the
production of more electricity with less quantity of fuel. Gradual improvements
in the energy sector are taking place where electricity is substituting other forms
of energy in nal use. This will enhance the role of electricity in environmental
preservation by reducing emissions from other sources. Clean coal technologies
are still being developed [4]; carbon sequestration technologies, although showing
promise, are still in their infancy and it will be many years before they become
Conservation in consumption as well as improved efciency in electricity util-
isation are important means for attaining the environmental goals. Conservation
and efciency-in-use measures do not always require large investments and should
therefore be the rst technologies and methods to be applied. But they do require
policies. The main promoter of these measures is the pricing mechanism (tariffs).
Another powerful way of promotion is through informing and educating consumers
and soliciting their participation in conservation and efciency measures and in
investing in energy-saving technologies. Heat pumps, electric arc melting, induc-
tion heating, electric transit, and efcient electric house appliances and modern
electricity-saving lighting can signicantly reduce energy and electricity consump-
tion without compromising consumers production and welfare. Such electricity
conservation, and efciency in use, plus switching from primary energy use into
electricity, lead to substantial reductions in emissions and environmental impacts
of electricity and energy without having to invest in capital-intensive environmental
Because of the nature of fuels utilised in the electricity supply industry and the
rapidly growing utilisation of energy in the form of electricity, the environmental
impacts of electricity production are gaining more importance than those of other
forms of energy and this demands a thorough understanding of their nature. Such
impacts can have direct nancial costs (damage to trees and forests and pollution
to land and other resources that can be nancially assessed) as well as intangibles
(mainly health). These damages can be grouped as social costs. There are also the
possible long-term environmental costs of global warming. Some of these environ-
mental impacts have to be avoided through investment. A cost/benet analysis to
the costs involved in controlling emissions from the electricity supply industry and
the benets derived out of this action have to be undertaken. Unfortunately, a lot of
environmental damage costs resulting from electricity production are very difcult to
quantify and the science of environmental accounting is still in its infancy [5]. This
chapter will try to record the environmental detrimental effects of electricity, methods
of quantifying them(where possible) and analyse technologies, investments and other
means of control.
Environmental considerations and cost estimation in project evaluation 99
8.2 Environmental impacts of electricity fuels
Electricity production can have many environmental health and safety impacts.
Mining for electricity fuels, their transport and storage also contribute to pollu-
tion. So does the disposal of the combustion-process products of ash and other solid
wastes. Coal, in environmental terms, represents particular concerns. Its consump-
tion by-products are more polluting than other fuels and they contain higher carbon,
and NO
emissions and much more solid waste. Environmental health and other
safety impacts of coal mining and transport can be substantial.
The main categories of impact of pollution are local, regional and global.
(i) Local impacts are mainly in the form of heavy hydrocarbons and particulate
matter (including sulphur akes), which are deposited within hours and can
travel up to 100 km from the source.
(ii) Regional impacts involve emissions and efuents, the most important of which
are SO
aciddepositions, whichhave a residence time inthe atmosphere of a few
days and may travel to a few thousand kilometres thus causing cross-boundary
(iii) Global pollution is exemplied by CO
emissions and other gases (mainly
methane), which have long residence times in the atmosphere. Methods of
costing the three impacts are described in the following section. The vari-
ous impacts of the fuel system components are detailed in Table 8.1. Carbon
emissions of the fossil fuels are shown in Table 8.2, and the global warming
potentials (GWP) of different emissions are in Table 8.3.
Not all impacts of electricity utilisation are detrimental. Substituting electricity
for other forms of energy helps in improving the efciency of use of primary fuels.
Electricity has replaced most other fuels in urban societies and has improved the
qualityof urbanandbuilt-upenvironments andof environmental management through
various instrumentation and control technologies. The fact that electricity is highly
controllable signicantly improves the efciency of heating and cooling systems,
as well as machinery and lighting through shorter warm-up and cool-down periods.
Therefore electricity can play a signicant positive role in safeguarding local, regional
and global environment if measures to control the detrimental supply side impacts
are dealt with in an economically sound manner.
Global warming potentials (GWP) show that greenhouse gas emissions (GHGs)
other than CO
can pose a much larger risk to the environment if emissions continue
unchecked. GWPs are a measure of the relative radiative effect of a given substance
compared to CO
, over a chosen time horizon. They are an index for estimating
the relative global warming contribution due to atmospheric emission of 1 kg of a
particular GHGcompared with 1 kg of CO
. The atmospheric response time of CO
subject to substantial scientic uncertainties, owing to limitations in the understanding
of key processes, including its uptake by the biosphere and ocean. The numerical
values of the GWPs of all GHGs can change.
100 Economic evaluation of projects in the electricity supply industry
Table 8.1 Environmental impacts of fuel system components
generation fuel
Key impact
Coal Groundwater contamination
Land disturbance, changes in land use and long-term ecosystem
Emissions of SO
, NO
, particulates with air quality implications,
heavy metals leachable from ash and slag wastes
Possible global climatic change from CO
Lake acidication and loss of communities due to acid depositions
Oil and gas Marine and coastal pollution (from spills)
Damage to structures, soil changes, forest degradation, lake acidication
from S and N emissions
Groundwater contamination
Greenhouse gas emissions impact, e.g. possible global climate change
Hydroelectric Land destruction, change in land use, modication of sedimentation
Ecosystem destruction and loss of species diversity
Changes in water quality and marine life
Population displacement
Nuclear Surface and groundwater pollution (mining)
Changes in land use and ecosystem destruction
Potential land and marine contamination with radionuclides
(accident conditions)
Renewable Atmospheric and water contamination
Changes in land use and ecosystem
Noise from wind turbine operations
Possible air quality implications
Source: Reference [6].
Table 8.2 Carbon emissions of fossil
Tonnes of carbon per TOE
Coal 1.08
Fuel oil 0.84
Natural gas 0.64
TOE = tonnes of oil equivalent.
Source: Reference [7].
Environmental considerations and cost estimation in project evaluation 101
Table 8.3 Global warming potentials (GWP)
Gas Global warming potential time horizon
20 years 100 years 500 years
Carbon dioxide (CO
) 1 1 1
Methane (CH
) 62 (56) 23 (21) 7 (6.5)
Nitrous oxide (N
O) 275 (280) 296 (310) 156 (170)
Sulphur hexauoride (SF
) 15 100 (16 300) 22 200 (23 900) 32 400 (34 900)
Source: IPCC (2001) (1995 IPCC gures in brackets).
VSL Value of life year lost
Chronic mortality from fine particles
Geographical range: whole of Europe
Figure 8.1 Relative ranking of external cost estimates (excluding global warming
impacts) for different electricity generation technologies under changing
background assumptions. External costs are normalised to the external
costs for the coal fuel cycle [8]
8.2.1 Environmental impact of different generation fuels
The ExternE project is a major research programme launched by the European
Commission at the beginning of the 1990s to provide a scientic basis for the quan-
tication of energy related externalities and to give guidance supporting the design
of internalisation measures [8].
In spite of the existing uncertainties, ExternEresults were quite robust with regard
to the relative ranking of different electricity generation technologies. Figure 8.1
102 Economic evaluation of projects in the electricity supply industry
clearly shows that even under different background assumptions electricity generation
from solid fossil fuels is consistently associated with the highest external cost, while
the renewable energy sources cause the lowest externalities.
8.3 Environmental evaluation
It is not easy to estimate the cost of environmental impacts of electricity production,
local or regional. Local environmental impacts depend on the quality of fuel utilised,
the site of the power station with regard to population centres, and the availability
of other amenities. A power station sited in the desert will have much less impact
on environmental health than a similar power station close to population centres and
forests. A hydro-electric power station in an uninhibited area will have a lot less
environmental impact than a hydro-power station that leads to relocating people or to
the destruction of villages and agricultural lands.
Environmental impacts that can be quantied in nancial terms should be incor-
porated in the economic evaluation of the project. Those that cannot be directly
evaluated (such as loss of bio-diversity, impact on health, etc.) should be researched
and quantied, whenever possible, and also incorporated as social costs. Such costs
have to be utilised in the economical evaluation used to identify the least cost and in
the calculation of the IRR and ERR. Detrimental environmental impacts can be less-
ened or alleviated through investment and a costbenet analysis of such investments
should be performed.
Today, emissions from power stations have been identied and most of them
can be evaluated in terms of their environmental impacts (see Table 8.1). Therefore
it is now possible, although somewhat difcult, to determine the cost of a power
facilitys environmental impact. This cost has to be compared with the capital invest-
ment needed for implementing suitable abatement technologies. Benets of capital
investments incorporating different abatement technologies and thus leading to dif-
ferent impacts should be compared to help identify the least (economic) cost project
8.4 Environmental impacts and the discount rate
The utilisation of the discount rate in evaluating environmental impacts was subject
to severe criticism on the grounds that environmental damage and costs appear many
years after project execution. As long-termcosts they are reduced to insignicance by
discounting (at a discount rate of 10 per cent, damage valued at 1 now and occurring
after 10 years will equal only 0.39 today). At the same time, project investments that
help the environment will also have long-term benets, which are greatly reduced by
discounting. Highdiscount rates alsoleadtoacceleratingthe exploitationof renewable
and non-renewable natural resources, such as fossil fuels, because they substantially
reduce their long-term value [9].
One strongreasonfavouringthe use of the present value of environmental costs and
benets fromdifferent perspectives over the use of the discount rates for investment by
Environmental considerations and cost estimation in project evaluation 103
individuals is that individuals are mortal while societies are quasi-immortal. Therefore
individuals, being mortals, tend to value the present in greater terms than societies,
because of the prospect of their early death. Such fears do not exist in the community.
The community, therefore, has reason to discount the future to a lesser extent than
individuals [10].
This argument calls for lowering the discount rate on environmental projects or
even not discounting their costs and benets at all. This, of course, can be a source
of difculty in evaluations where it will result in having more than one discount rate
for different cost/benet items and implies a different treatment of environmental
projects. Another approach would be to properly value, in economic and not just nan-
cial terms, environmental costs and benets and give them the appropriate weight in
project evaluation. Projects should be designed not to cause serious environmental
damage to irreplaceable critical natural capital. Any long-termchange in the expected
relative value of environmental assets should also be reected in their appraised prices.
Therefore costbenet analysis of environmental projects is better made at the
same discount rate as that used for standard investment evaluation. However, more
thorough research and estimation have to be undertaken of all environmental costs
and benets, particularly those of non-monetary and irreversible consequences, and
the values incorporated into the analysis. Having said that, climate change is a long-
termproblem, so that froman economists perspective discounting is a very important
issue. In such a case three different discount rates (0, 1 and 3 per cent) are normally
utilised. Although the models cover a time horizon of 100 years only, the change in
discount rate depending on the valuation alternative might even lead to a change in
the sign of the aggregated marginal damage costs (short-termbenets might dominate
the global estimate when using the 3 per cent discount rate, with damage occurring
after 100 years having a 5 per cent value today) [8].
8.5 Health and environmental effects of electricity
The vast majority of the environmental and health effects of electricity are from the
generation side, particularly when ring low-quality coal. Hydro-electric and natural-
gas red facilities have lower environmental impacts. Applying adequate safeguards
have rendered nuclear power stations safe. Sections 8.5.1 and 8.5.2 briey detail the
health and environmental impacts of electricity generation facilities.
8.5.1 Direct health effects
Fossil-red plants
In the case of oil- and coal-red plants, a signicant public health risk results from
exposure to the large amounts of gaseous and solid wastes discharged in the combus-
tion process. These emissions include SO
, CO, NO
, hydrocarbons, and polycyclic
organic matter. Coal-red stations also discharge y ash, trace metals, and radionu-
clides. The presence of these pollutants leads to increased incidence of respiratory
disease, toxicity and cancer. Disposal of the resulting solid waste leads to health risks
104 Economic evaluation of projects in the electricity supply industry
associated with leachate and groundwater contamination. Natural gas-red plants
pose a public health risk of NO
and particulate emissions, but are signicantly less
hazardous to health than oil- or coal-red plants.
Large-scale hydro-electric plants pose relatively few health risks compared with
fossil-red plants. However, still water reservoirs create ecological environments
favourable to the spreading of parasitic and waterborne disease. Relatively low pub-
lic risks exist from the low probability of dam failures. Biomass plants emit lower
levels of SO
compared with oil- or coal-red plants, but have higher emissions
of potentially carcinogenic particulates and hydrocarbons. Other renewables such as
solar photovoltaic and thermal, geothermal, tidal, and wind power, pose no signicant
occupational or health risks at the generation stage.
Transmission and distribution
The health impacts of transmission and distribution, particularly ultra high voltage
alternating current (UHVAC) and high voltage direct current (HVDC), are well docu-
mented [11]. It has been veried that human sensitivity to short-term exposure to
a strong electrostatic eld could be signicant. Studies to measure the biological
effects of electric elds and of chronic exposure to electric elds on people, animals
and plants have been carried out. Since 1981 dozens of studies examined the incidence
of cancer among workers exposed to electric and magnetic elds (EMF). Results were
inconsistent. While some studies showed a slight rise in mortality of leukaemia or
brain cancer among electrical workers others showed no such tendency. Recent more
extensive and detailed studies and research were also inconclusive. Any negative
health effects of transmission and distribution may be relatively minor compared to
the health effects of the alternative option: siting power generation facilities closer to
population centres [12].
8.5.2 Environmental impact
As mentioned earlier, pollution resulting from electricity generation can be broadly
categorised as having local, regional, and global environmental consequences.
Regional and global impacts are caused primarily by the emission of atmospheric
pollutants that have longer residence times, causing dispersal over larger areas. Most
important among these gases are SO
, which causes acid deposition or acid rain,
and CO
, which is a greenhouse gas and can contribute to global warming.
Local impacts
Purely local impacts include those caused by fossil-red power plant emissions to
the atmosphere (particulates, leaded compounds, volatile organic compounds, dust)
that result in air quality degradation causing damage to crops, structures, local
ecosystems and posing a health hazard. This is also the case with emissions from
waste-to-energy plants. Efuent disposal from fossil-red and nuclear plants can
Environmental considerations and cost estimation in project evaluation 105
lead to groundwater contamination with long-termirreversible pollution implications.
The existence of potential carcinogens and mutagens in the waste can have negative
impacts on health and agricultural productivity. Improper disposal of radioactive
waste from nuclear plants (e.g. discharge of liquid waste into the sea) can cause
destruction of sheries and other health hazards through contamination of the water
Hydro-electric power generation is perhaps the one electricity generation system
that has only local, but occasionally major, environmental consequences. These con-
sist of the damage caused by dam construction: destruction of habitats and loss of
local/national biodiversity, the inundation of productive land and forests, and possi-
bly the loss of cultural sites and mineral resources. Watershed disturbance sometimes
leads to increased ooding and low ow in the dry season. On major river systems,
this can have inter-regional and/or transitional consequences causing signicant polit-
ical and social unrest over water rights. The existence of still water contributes to the
spread of waterborne and parasitic disease. The massive displacement of people that
is often required represents a signicant social cost and can lead to increased use of
marginal lands.
Environmental impacts from other renewables are related primarily to the loss of
land use represented by the high space intensity of solar energy, and the noise caused
by wind-powered generation.
Regional impacts
Coal- and oil-red power stations emit signicant amounts of sulphur dioxide and
nitrogen oxides to the atmosphere. The transport of sulphur dioxide occurs over long
distances (greater than 1000 km), causing the deposition of emission products over
national boundaries. This may result in ecologically sensitive ecosystems receiving
depositions of sulphur well above carrying capacity.
Acid deposition caused by sulphur and nitrogen oxides results in damage to trees
and crops, and sometimes extends to acidication of streams and lakes, resulting
in destruction of aquatic ecosystems. It also leads to the corrosion, erosion, and
discolouration of buildings, monuments and bridges. Indirect health effects are caused
by the mobilisation of heavy metals in acidied water and soil.
While electricity generation accounts for less than half of the total anthropogenic
nitrogen oxide emissions (the majority of the remainder is caused by motor vehicle
exhausts), the portion of SO
emitted by electricity generation is substantial. For
example, Europe (including Eastern Europe) emitted close to a third of the worldwide
anthropogenic sulphur emissions in the early 1980s. It is estimated that in 1985,
60 per cent of European SO
emissions were the result of electricity production.
Other regional environmental impacts are caused by radiation effects on health,
and land/water contamination caused by severe nuclear accidents. As mentioned
before, changes in hydrological ow and water conditions caused by dams can also
have regional consequences. Thermal-power plants could also have a negative effect
on aquatic organisms, sheries, etc., owing to the water temperature increase that
could be caused by diffused thermal efuent.
106 Economic evaluation of projects in the electricity supply industry
The relative contribution of electricity generation to the prospects of overall
global warming (mainly in the form of CO
emissions) has been estimated at about
20 per cent till now, but rapidly increasing, compared with about 78 per cent caused
by deforestation. Of the contribution of fossil fuels, coal and oil each contribute about
40 per cent of anthropogenic CO
emissions, and gas contributes about 15 per cent.
OECD and other European countries account for about 70 per cent of global fossil
fuel CO
emissions at present. However, energy consumption as a whole is the single
largest contributor to greenhouse gas emissions in developing countries. Both India
and China will be forced to increase coal-red generation to meet the growing energy
needs of their citizens for electricity through utilising domestic energy sources; some
of this coal is low quality with enormous local, regional and, maybe, global impacts.
8.6 Investment costs in reducing dangers
to health and environmental impacts
The modication of existing electricity-generation facilities to reduce emissions is
achieved through the installation of emissions-control equipment that reduces SO
, and particulates. Emission controls add a signicant amount to a plants capital
and operating costs. For example, in the United States pollution control costs are esti-
mated at 40 per cent of capital and 35 per cent of operating costs [12]. For an entire
pollution control system in a German power plant, SO
control represents 13 per cent
of total the capital cost, NO
control adds 6 per cent, and particulate control another
4 per cent. Control equipment in Japan constitutes an estimated 2025 per cent of
total capital costs for a new coal-red plant, and 1520 per cent of total electricity-
generation costs. Add-on technologies of this nature do not change proportionately
with the size of the facility and, as a result, pose relatively high costs to smaller
facilities. Therefore their effects on cost of generating facilities in developing coun-
tries are larger. Generally speaking, pollution control for large electricity facilities
will increase capital cost by 25 per cent and electricity production cost by up to
20 per cent; for smaller facilities the increase can be larger.
Particulate-control technology has a long history of use in power plants. The most
cost-effective methods are electrostatic precipitators and fabric lters, both of which
achieve 99.55 per cent particulate removal. Costs for both technologies are, for capital
costs, about 4 per cent of total cost of plant and, for operating costs, about 58 per cent
of total plant production cost. Fabric lters are especially relevant for low-sulphur coal
use. Other methods include wet scrubbers, which have a high levelised annual cost,
and mechanical collectors, which are not efcient enough (at 90 per cent removal) to
meet most stringent environmental standards in developed countries.
In terms of electricity production, carbon-sequestration technologies are not
commercial yet, as there are no developed and cost-effective pollution-control tech-
nologies that can reduce carbon emissions. However, natural-gas combined-cycle
conversion eliminates sulphur emissions, reduces NO
emissions by 90 per cent,
and reduces carbon emissions by almost 60 per cent. In the United Kingdom, it has
been estimated that it is cheaper to build and operate a combined-cycle gas-turbine
Environmental considerations and cost estimation in project evaluation 107
(CCGT) plant, as opposed to retrotting an existing coal-red plant. CCGT plants
are more thermally efcient than conventional fossil-red plants. They are also more
energy efcient, and less costly, than the new clean coal technology uidised bed
combustion (which reduces sulphur and NO
emissions without the installation of
emissions control systems).
8.7 Evaluation of the environmental cost of
electricity generation
Environmental impacts [13] of electricity generation were detailed in Table 8.1. The
most serious impacts, which are difcult and very expensive to deal with, are air
pollution damage in the form of emissions of SO
, NO
, particulates with air quality
implications, and greenhouse gases, particularly CO
. Such emissions will have a
detrimental impact on health, buildings and similar properties, forests and climate
change costs.
8.7.1 Assessing health impacts and costs
The major part of the dose of air pollutants inhaled by the general public is caused by
road transport facilities and fuels and not by electricity production. There is remark-
able evidence of linkages between very small particulate matter under 10 mdiameter
) and mortality and detrimental health effects. Such very small particulate
matter (PM
) is normally produced by transport activities and not by electricity
generation utilising coal, which produces the particulate matter of general dimensions.
There are many ways of valuing the impact [14] of air pollution on human health
and well being. Willingness to pay (WTP) involves asking individuals questions about
their willingness to pay, through a voluntary contribution or tax mechanism, to reduce
air pollution to a safe level. A more direct method is that of doseresponse, which
involves nding a medical relationship between air pollution and observable health.
Morbidity effects are valued by the cost of illness (COI) approach. This uses the cost
of medical treatment and lost output as the social cost of the air pollution. However,
the COI approach may be inferior to the WTP, since it ignores the disutility of illness.
In assessing the effect of air pollution on health, the detrimental health effects are
caused by the small particulate matter (PM
) emerging fromcar exhausts, rather than
the usual general dimension particulate matter emitted from power-station chimney
stacks. Utilising WTP methods, it is estimated that annual health costs of PM
emissions in the UK, mostly from transport, may be something of the order of
14 billion [15]. This is far more damage than that can be caused by electricity
8.7.2 Assessing damage to buildings, properties and
forests by air pollution
and NO
are the main air pollutants that are transboundary and can cause damage
to buildings and similar properties, as well as to forests. In addition, the deposition of
108 Economic evaluation of projects in the electricity supply industry
sulphur and nitrogen species causes oxidation of soils and fresh water. SO
are mainly caused by ring fossil fuels, particularly for electricity generation. Brown
coals, in particular, have a very high sulphur content and cause more emissions per
unit of electricity generated than ordinary hard coal or other fossil fuels. SO
can be a serious cause of local and regional damage with signicant nancial cost.
Such emissions, and correspondingly damage cost, can be signicantly reduced
by either fuel switching or by add-on measures to abate emissions. Fuel switch-
ing involves using cleaner fuels. Natural gas (and LNG) is relatively benign with
no SO
emissions and, if economically available, can signicantly contribute to
the reduction of air pollution. Utilisation of energy-efcient generation technolo-
gies and conservation can also signicantly help. If fuels such as natural gas are
not available, then the alternative for reducing air pollution is to utilise add-on mea-
sures. These are technologies and facilities that abate emissions, mostly of SO
and also particulate matter. Utilising these measures should be pushed to the
extent that the cost of additional measures should be equal to their environmental
Sulphur reduction can be achieved prior to combustion by washing or by adding
powdered limestone during ring, which can reduce the sulphur emissions by almost
one third. However, major reductions are achievable after combustion by ue gas
desulphurisation (FGD), by using limestone (which yields gypsum), or by regenera-
tive techniques that yield sulphuric acid. Utilising all three techniques can reduce the
sulphur emission by almost 95 per cent, but at enormous investment and operational
cost as explained earlier. In order to assess the extent of these measures, it is essential
to know two things: the marginal cost of abatement per each unit of sulphur and the
cost of environmental damage that unit of sulphur causes. Cost curves for sulphur
abatement can be plotted showing the extent of abatement against cost.
Assessment of environmental damage is much more diffucult [16]. Emissions
are carried away over wide distances by complex weather patterns. Acidation takes
place in dry and wet weather (acid rain), causing the damage described above. In the
case of damage to building materials, the extent of damage depends on the extent
of emissions and air pollution, and also on the type and quality of materials used.
Stone buildings are less affected than brick buildings. The cost of the damage can
be assessed by two methods: doseresponse functions and the maintenance cycle
In the doseresponse functions method, the extent of damage is assessed by dose
response functions that are normally prepared for building stones and metals, where a
critical damage level is dened for each material. The value of the national cost of the
air pollution will equal the cost for replacement or repair of the damaged material.
The maintenance cycle approach starts with the same assessment of damage
to materials by doseresponse functions. However, it recognises that a reduction
in emissions concentration will lead to a corresponding reduction in maintenance
requirements of building material. Therefore, utilising the doseresponse function,
an estimation of the saving in maintenance is allocated for a certain reduction in
emissions level through a corresponding investment. Avalue of total national savings
is calculated for a given reduction in SO
concentration. Utilisation of either method
Environmental considerations and cost estimation in project evaluation 109
has to be handled with care, taking into consideration the different factors other than
(like weather) that contribute to material damage.
To evaluate costs of damage of SO
, a case of a 2 GW power station utilising
1.6 per cent sulphur coal, operating at an efciency of 36 per cent, and not tted with
FGD facilities was considered. The cost adder in terms of p kWh
was computed.
This indicated that cost of damage to buildings in the UK is put at 0.07p kWh
within a range of 0.040.19p kWh
, depending on the assumptions utilised and the
location of the power station with respect to urban areas [17].
A similar approach was used to assess damage by SO
to European forests.
Damage functions were created to chart the annual loss in the value of wood
(estimated by multiplying the estimate of volume damaged by a price of 23 m
as affected by acid depositions in grams per square metre per annum. For the above
described power station, estimated cost adders are 0.05 and 0.01p kWh
for SO
and NO
, respectively [18].
8.7.3 Climate change costing
Climate change due to emission of greenhouse gases (CO
, methane) is the most
controversial aspect of air pollution. This is because of the existence of minimal
evidence at present and the fact that damage can only be ascertained in the far future,
50 years or more. CO
emissions are the main source of greenhouse gases. These are
gases that are supposed to accumulate in the atmosphere with a long residence time,
leading to higher long-term atmospheric temperature.
Electricity generation was supposed to account, in 2002, for about one third of
global greenhouse gases emissions fromenergy utilisation [2]. With increased growth
of electricity generation, at a rate of almost 1.5 times that of total primary energy
utilisation, electricity production will assume a large proportion of emission of gases,
particularly CO
(37 per cent of global energy emissions in 2020), that may cause
signicant climate change in the future. Developing countries, particularly China and
India, which have very high electricity demand growth potential, are dependent on
local coal supplies that emit increasingly large amounts of CO
in the long term;
although it is not easy to ascertain the extent and results of such emissions in the
future, and correspondingly the extent of damage to human welfare and property. It is
wiser to adopt the minimum regrets policy, which advocates the reduction in the rise
of greenhouse gases emissions, and preferably their stabilisation as soon as possible,
through energy efciency, conservation and utilisation of relatively benign fuels like
natural gas [19].
It is not possible to assess, with any degree of certainty, the future implications
of increased emissions or concentration in the atmosphere of CO
, and correspond-
ingly to understand the mechanisms of global warming and its social and economical
impact. It is, however, certain that whereas other air pollutants have local and regional
impact, that of CO
is going to be global and can be much wider reaching. Whereas
the impact of other air pollutants can be contained in a very signicant way by tech-
nology (other than by fuel switching, efciency and conversation), containment of
emissions is taking more time. Zero carbon emissions will be possible in the
110 Economic evaluation of projects in the electricity supply industry
near future, but they may prove to be costly; correspondingly, only industrialised
countries will be able to afford them (see also Chapter 9).
Climate change can have two sorts of impact. One is market related, which is
reected in monetary terms and national accounts. The other is non-market related in
that it has an intangible effect, like impacts on human amenities and ecosystems. Such
damage can usually be estimated by the WTP concept. However, such estimates are
not always available for assessment of global warming impacts. Other indicators are
utilised to assess the welfare impacts on climatic change such as reduction in revenues
or returns from capital and land. The IPCC Working Group III (1995) [20] estimates
that a future impact of an atmospheric CO
concentration of twice the pre-industrial
level (a scenario called 2 CO
), will have the following damage costs:
world impact: 1.52.0 per cent of world GNP,
developed country impact: 11.5 per cent of national GNP,
developing country impact: 29 per cent of national GNP.
Note that these gures include both adaptation costs and residual damages.
Such impacts are believed to vary fromone country to another. Very fewcountries
can have benecial impacts. Asia and Africa, which accommodate most of the worlds
population, are likely to suffer extreme damage owing to severe life and morbidity
impacts. However, these estimates are not comprehensive and are highly uncertain.
Greenhouse gases are stock pollutants; that is, an emission now will have long-
term effects that stretch over several decades. What is important is to estimate the
marginal cost of CO
emissions, that is, the discounted present worth extra damage
for one extra ton of carbon emitted. To achieve this, there is a need to consider two
scenarios: the rst is the present value of future damages associated with certain
emissions, and the second has marginally different emissions in the base period. The
results of such an approach depend greatly on the choice of the discount rate and
variations in scenario assumptions, with results varying between the wide margin of
US$5US$125 as a marginal cost of CO
emission (1990) per ton of carbon. Most
estimates are on the lower margin. Future emissions will have a higher marginal cost
owing to the stock effect [21].
The marginal social costs per ton of air pollutants emitted were valued by a com-
mission of European Communities/United Stated (CEC/US 1993), and the results
are shown in Table 8.4. Such gures are useful in evaluating the economics of abate-
ment facilities and measures, and utilising evaluation techniques described previously.
A study [22] of UK air pollution damage is demonstrated in Figure 8.2. The
gure clearly depicts that SO
, mainly from power generation, causes the greatest air
pollution damage in the UK. However, over recent years, there has been a dramatic
decrease in SO
emission. This resulted fromincreased public awareness and demand,
which led to regulatory policies, switching from coal to cleaner fuels, efciency
measures, the wider renement and adoption of emissions inhibition technologies.
It has been estimated [23] that the average damage costs per unit electricity gener-
ation from fossil power plants in EU-15, in 1990, amounted to 6.4 cents kWh
, this
was more than the actual cost of production; since then there have been considerable
Environmental considerations and cost estimation in project evaluation 111
Table 8.4 Marginal social costs per ton of air pollutant
emitted (US$) 1993 [20]
Health 1530 470 10 350
Forestry 1760 1220
Materials/buildings 480 320 320
Climate change 7
Total 7 3770 2010 10 670
1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990


Figure 8.2 Cost of air pollution damage in the UK [22]
8.8 References
1 JARET, P., Electricity for Increasing Energy Efciency, EPRI J., April/May
1992, 17, (3)
2 World Energy Outlook, International Energy Agency (IEA) (OECD, Paris,
3 KHATIB, H.: Electrication for Developing Countries, EPRI J., September
1993, 18, (6)
4 Foreign Market for U.S. Clean Coal Technologies, Department of Energy,
DOE/FE-0317, Washington, DC, 1994
112 Economic evaluation of projects in the electricity supply industry
5 PESKIN, H. M., and LUTZE, E.: A survey of resource and environmental
accounting in industrialized countries, The World Bank, Environment working
paper 37, 1990
6 Senior expert symposium on electricity and the environment, IAEA, Helsinki,
Finland, May 1991
7 Greenhouse gas emissions the energy dimension, IEA (OECD, Paris 1991)
8 KREWITT, W.: External costs of energy, Energy Policy, August 2002, 30, (10)
9 AWERBUCH, S. and DEEHAM, W.: Do consumers discount the future
correctly?, Energy Policy, January 1995, 23, (1)
10 The economic appraisal of environmental projects and policies, OECD and
Economic Development Institute of the World Bank, 1995.
11 PERRY, T.: Todays view of magnetic elds, IEEE Spectrum, 1994, 31, (12)
12 MODRE, T.: Utility workers and EMF health risks, EPRI J., 1995, 20, (2)
13 KHATIB, H., and MUNASINGHE, M.: Electricity, the environment and sus-
tainable world development, WEC Commission: Energy for Tomorrows World
plenary session, 8, World Energy Council 15th Congress, Madrid, 1992
14 CAITHROP, E., and MADDISON, D.: The dose response function approach to
modeling the health effects of air pollution, Energy Policy, July 1996, 24, (7)
15 PEARCE, D., and CROWARDS, T.: Particulate matter and human health in the
UK, Energy Policy, July 1996, 24, (7)
16 APSIMON, H., and WARREN, R.: Transboundary air pollution in Europe,
Energy Policy, July 1996, 24, (7)
17 APSIMON, H., and COWELL, D.: The benets of reduced damage to buildings
from abatement of sulphur dioxide emissions, Energy Policy, July 1996, 24, (7)
18 GEOGORY, K., WEBSTER, C., and DURK, S.: Estimates of damage to forests
in Europe due to emissions of acidifying, Energy Policy, July 1996, 24, (7)
19 Energy for Tomorrows World, World Energy Council (Kogan Page Ltd.,
London, 1993)
20 Externalizes of the fuel cycle: externproject, Commissionof the EuropeanCom-
munities/United States (CEC/US), working documents 1,2,5 and 9, Directorate
General XII, European Commission, Brussels
21 FRANKHAUSER, S., and TOL, R.: Climate change cost, Energy Policy, July
1996, 24, (7)
22 HAMILTON, K., andATKINSON, G.: Air pollutionandgreenaccounts, Energy
Policy, July 1996, 24, (7)
23 KREWITT, W. et al.: Environmental damage costs from fossil electricity
generation in Germany and Europe, Energy Policy, March 1999, 27, (3)
Chapter 9
Electricity generation in a
carbon-constrained world
9.1 Introduction
External factors, most importantly, the needtopursue the goals of sustainable develop-
ment, have had a growing inuence on the future of the ESI. International agreements
like the Kyoto Protocol and the anxiety of governments to ensure energy security are
modifying the way the business of electrical power is being conducted [1].
In May 2001, the US government formulated its energy policy. In February 2002,
the UK government published The Energy Review. This is a consultation paper,
which recommends that the overall aim of future UK energy policy should be the
pursuit of secure and competitively priced means of meeting our energy needs, subject
to the achievement of an environmentally sustainable energy system. In the short
term it sees the expansion of the role of renewable generation and the promotion of
energy efciency as being the most cost-effective ways of meeting these policy aims
and the Kyoto targets. In addition to the existing target of 10 per cent of electricity
being generated from renewable resources by 2020, it also proposes a target of 20 per
cent improvement in domestic energy efciency by 2010, and a further 20 per cent
improvement by 2020.
For the longer term, the review paper recognises the level of uncertainty involved
in trying to predict too far into the future. Given that there is a strong chance that
there will be even more stringent carbon-reduction targets post-2012, the review
paper recommends retaining maximum exibility by creating and keeping open all
low-carbon energy options. These options include renewable electricity generation,
small-scale combined heat and power (CHP), nuclear power and clean coal.
Most of the environmental achievements will have to be attained through more
efcient production and utilisation of electrical power. A new factor has come into
play: the ESI plans are increasingly becoming driven by governmental political
considerations, as agreed in international forums.
114 Economic evaluation of projects in the electricity supply industry
9.2 Climate conventions and Kyoto
The most signicant international environmental treaty ever drafted [2], the United
Nations Framework Convention on Climate Change (UNFCCC), was agreed at the
1992 Earth Summit in Rio de Janeiro and sets out a framework for action to control
and cut greenhouse gas emissions. A Protocol to the Convention was subsequently
adopted in 1997 at the Third Conference of the Parties held in Kyoto, Japan. This
provides a practical international process to reduce emissions that can contribute to
global warming. Under the Kyoto Protocol, industrialised-country participants or
parties agree to reduce their overall emissions of the six greenhouse gases (GHGs)
by an average of 5.2 per cent below a 1990 baseline between 2008 and 2012, the
so-called rst commitment period (see Section 9.2.1).
One of the primary targets for attaining carbon emissions reduction will be the
power sector. Modern power stations, particularly those operating in a combined-
cycle mode have very high efciencies and use relatively benign fuels such as natural
gas (see Figure 9.1). Such efciencies, at nearly 60 per cent, are almost twice the
efciency of vintage available plants. Emissions fromcombined-cycle high-efciency
plant ring natural gas is only 40 per cent of that of a modern coal-ring thermal
power plant (even less in case of brown coal). Shutting down an old coal-ring plant
and replacing it by a modern CCGT plant will reduce carbon emissions by a factor
of 33.5. Signicant achievements have been made recently in higher CCGT plant
efciency (see Figure 9.2).
The power sector itself can expect to face various forms of scal tightening to
curb emissions, such as taxes levied on energy used as well as additional and tougher
regulatory targets for energy efciency. The power sector will also be encouraged to
kg CO
0.78 0.76
0.020 0.004 0.025
Coal Oil Natural
Wind Water
Operation Fuel supply Construction
Alongside nuclear, solar, wind
and hydro-power, natural gas
offers a suitable alternative for
reducing CO
. The emissions
are relatively low, and new
combined-cycle power plants
have very high efficiencies.
Figure 9.1 Comparison of CO
emissions [3]
Electricity generation in a carbon-constrained world 115
1990 1992 1994 1996 1998 2000


During the past decade, the efficiency, i.e. the energy utilisation, of
combined-cycle power plants has been improved by several percentage
points. Improvements in steam turbines and an increase in gas turbine
inlet temperature were the key factors behind this gain.
Improved compressor
and turbine efficiency
Higher gas turbine
inlet temperature
Improved steam
cycle efficiency
Figure 9.2 Combined-cycle power plant efciency development [3]
participate in the so-called Kyoto exible mechanisms, a raft of activities permitted
under the Protocol to curb emissions.
9.2.1 Case Study: the Kyoto Protocol and the Marrakech
declaration and accords
The so-called Annex B countries all signatory countries that have set absolute
emissions goals for the six most important GHGs have committed themselves to
reducing their average emissions by 5.2 per cent relative to 1990 levels by 2012.
Germany aims to reduce greenhouse gas emissions by 2125 per cent, which equals
212 million tons of CO
The Kyoto Protocol was planned to go into effect immediately after the World Summit
on Sustainable Development in Johannesburg in September 2002, if a minimum of
55 countries that accounted for at least 55 per cent of CO
emissions in 1990 had
ratied the agreement by that time.
Approved instruments for attaining emissions objectives:
1 Direct national reduction of GHGs
2 Clean Development Mechanism (CDM)
3 Joint Implementation (JI)
4 International Emissions Trading (IET).
116 Economic evaluation of projects in the electricity supply industry
Verication and sanctions
All countries have committed themselves to regular publication of gures on
greenhouse gas emissions and reductions achieved. A commission will supervise
compliance. If commitments are not fullled, sanctions may be enacted. For every
ton of the CO
emissions target not achieved by 2012, an additional reduction of
1.3 tons must be achieved later.
Assistance for developing countries
Several funds for implementing environmentally friendly policies in developing coun-
tries have been set up. Developing countries are not required to implement concrete
climate protection measures until 2012.
9.3 Electricity generation and climatic change agreements
Electricity generation is going to be the primary target for emissions reductions as
agreed to by climatic change agreements. This is because of the following points.
An increasing share of nal energy is being utilised in the form of electricity.
Prospects for curbing emissions, through improved efciency, cleaner fuels,
renewable and nuclear power and similar means, are easier and with more sig-
nicant results in the case of power generation than in other energy conversion
processes. New power-generation technologies will signicantly assist in this
Emissions from power generation are concentrated in one place the power
station where it is easier to deal with.
Electricity lends itself more easily to project mechanisms that allow for emission
reductions through emissions trading and similar exible mechanisms.
The growing importance of global CO
emissions from power generation are
demonstrated in the following Table 9.1, adopted from IEA projection.
Table 9.1 Electricity contribution to CO
1971 1977 2010 2020
Global CO
emissions (Mt) from fossil fuels 14 753 22 984 30 083 36 680
Emissions from power generation (Mt) 3885 7663 10 671 13 479
Electricity/global (%) 26.3 33.3 35.8 36.8
Source: IEA WEO 2000
Electricity generation in a carbon-constrained world 117
Table 9.2 Carbon emissions forecasts for the UK
Carbon emissions in 2010
(million tons)
Percentage change between
1990 and 2010
Power generation 45.1 16.1
Energy-intensive industries 11.6 21.0
Other industries 12.6 15.1
Road transport 30.4 1.7
Air transport 1.9 22.7
Households 25.6 18.8
Commerce, etc. 9.9 5.1
Total 149.5 6.4
From Table 9.1 it is clear that power generation is assuming an ever-greater share
of global CO
emissions in spite of improvements in generation efciency and an
increasing share of natural gas in the process. Correspondingly any attempt to curb
global emissions will need to have power generation at its centre of interest.
In the UK it is expected that carbon emissions from power generation, in 2010,
will account to 45 million tons, i.e. 30 per cent of UK emissions in that year. This
is 16.1 per cent less than 1990 gures, and almost three times the national average,
signifying the potential for the power industry to reduce carbon emissions as detailed
in Table 9.2.
9.3.1 Flexible project mechanisms
These are designed to enable countries to deliver part of their committed emissions
targets Assigned Amounts through investment in projects that reduce emissions
in another country. Power generation is likely to be the most exible vehicle for such
projects implementation. There are two project-based mechanisms.
JI allows for investment by one developed country in a project that reduces
GHG emissions in another developed country (like a Western European coun-
try investing in a country in Eastern Europe). Emissions Reduction Units
(ERUs) generated by such projects can be used to meet the investing countrys
The CDM is designed to bring development to developing countries through
projects that result in a reduction in GHG emissions. Certied Emission Reduc-
tion (CERs) units are generated that can be purchased by a developed country
and used to meet its commitments (Figure 9.3).
To qualify under the CDM, projects put forward for registration to the UNFCCC
Secretariats executive board of the CDMmust meet a range of sustainability and envi-
ronmental criteria set down under the Kyoto Protocol. One of these is the requirement
for a veried project emissions baseline.
118 Economic evaluation of projects in the electricity supply industry
Identify project opportunity
Assess project eligibility criteria (sustainable
development, additionality, environmental benefit,
host government support, etc.)
Annual verification of emissions
Secure project funding (internal or through financial institutions)
Proceed with project
Assess economics of the project (including
the value of potential CERs)
Secure CERs
Register project with executive board of CDM
Register project with host country government
Verication of baseline and develop
emissions verification programme
Estimate GHG baselines and potential GHG reductions
Figure 9.3 The CDM process [2]
Likewise, under a verication programme specied in the registration process,
independent operational entities (third-party veriers) will periodically (probably
annually) verify GHG emissions from the project to enable them to recommend to
the executive board of the CDM the number of emissions credits (CERs) that can be
The Kyoto mechanisms offer the power-generation sector an incentive to invest
in emissions-reduction projects since ERUs and CERs should be funded with permits
issued as Assigned Amounts that can subsequently be monetised through emissions
trading. The potential size of the CDM market remains uncertain (especially given
the uncertainty over supplementary). But the best forecasts made to date suggest it
will be between 700 and 2100 million tons of CO
per year.
9.3.2 Emissions trading
This market mechanism is widely seen as the best way to help businesses identify the
most cost-effective options available to reduce emissions. The trading market should
Electricity generation in a carbon-constrained world 119
stimulate the development of new technology, because it sets a real cost on emissions
and provides market incentives to reduce that cost.
Several countries, for example, the UK and the Netherlands, are developing
national trading systems for GHGs. Trading in atmospheric emissions is not new;
both sulphur dioxide (SO
) and nitrogen oxide (NO
) emissions have been success-
fully traded in the US for many years. Emerging systems are based on a cap and
trade concept where participants stay within a basic allocated emissions allowance.
Where actual emissions of the business are above its total allowance for a given year,
then it must buy more allowances from the market to ensure compliance. Where
emissions are below an allocation, a company can sell allowances. The mecha-
nism for setting allowances requires a base year for which veriable data can be
reported and against which annual allocations can be set. Successful GHG emis-
sions have to be accurate, reliable and independently veried by a qualied third
Case study: UK Emissions Trading Scheme
The UK market ofcially launched this scheme in April 2002, but forward allowance
trades were carried out from September 2001 at prices between 4 and 6 per tonne
of CO
. Since the scheme was launched, many more trades have taken place at widely
varying prices, up to 6 per tonne.
Participation in the UK Emissions Trading Scheme [4] is open to most UK com-
panies and is voluntary. Electricity generators, the transport sector, households and
large landlls are not currently eligible to participate but may be able to enter the
scheme through emissions-reduction projects once the rules for this are established.
The government has provided signicant incentives for companies to participate in
the form of a rebate on the Climate Change Levy (CCL) for energy-intensive com-
panies and payments of 53.37 per tonne of CO
reduced for companies that entered
through an auction mechanismin March 2001. More than 6000 companies are eligible
to trade.
The UK scheme is a pilot, running from 2002 to 2006, and so it will still be in
operation as the EU scheme begins. The UK scheme is complicated by its interaction
with the CCL. Many companies that receive the CCL rebate have rate-based targets
and a gateway has been established between the absolute sector and the rate-based
sector to avoid ination of the absolute sector fromthe rate-based sector. The gateway
will close whenever aggregate sales from the rate-based sector to the absolute sector
equal the sales in the other direction.
An electronic registry records the holdings of allowances for each participant,
and tracks allocations, transfers, and nal cancellation or retirement of allowances.
Initially the registry will serve only the UK scheme, but in time it is envisaged that
it will act as the UKs national registry for international trading under the Kyoto
Protocol. By 2008, the registry will need to interface will overseas registries and
will become the main tool for tracking changes to UK-allowance holdings. Ulti-
mately, the government envisages that participants will be able to use any allowances
or credits obtained through the Kyoto mechanisms subject to the appropriate
120 Economic evaluation of projects in the electricity supply industry
9.3.3 Encouraging emissions reductions
In the UK, to raise the cost of energy use, the CCL is imposed on business and
public sector energy use from April 2001 whereby only good quality CHP plants
and renewable energy (other than hydro) of more than 10 MW capacities will be
exempt. Revenues from the CCL will be recycled to business via a 0.3 per cent cut
in employers taxation and 150 million ($219 million) of support for energy-savings
Energy-intensive sectors may also win an 80 per cent discount in the CCL under
special arrangements in the form of climate change agreements (CCAs) with the
government. These agreements set tough targets for participants to improve energy
efciency and/or reduce emissions. They do not dictate investment in specic tech-
nologies or techniques and they permit sectors to achieve their targets either by trading
emissions allowances with other companies within their CCA or by participating in
a wider national emissions-trading scheme.
9.4 Introduction to low emissions and
emissions-free power generation
Carbon sequestration is one of three critical elements in a three-pronged approach
to alleviate global climate change concerns. The other elements involve increasing
the efciency of energy generation and use, and reducing the carbon content of fuels
(e.g. natural gas and renewable and nuclear energy).
Carbon sequestration is an important option because it does not require a massive
overhaul of the worlds energy infrastructure. The goal is to develop sequestration
approaches that cost $10 or less per ton of carbon removed equivalent to adding
0.2 cents kWh
. Empirical evidence from advances in sodium carbonate technol-
ogy suggests that this goal is realistic, indicating 50 per cent CO
capture from a
power plant at $15 per ton of carbon removed. In the US as well as Europe carbon
sequestration programmes are underway on several fronts including carbon capture
and separation, sequestration in geologic formations/oceans/terrestrial ecosystems
and advanced concepts.
Nuclear-power generation and generation from most renewable sources are free
from carbon emissions. This should encourage their utilisation, particularly with the
prospect of carbon taxation, but with the following provisos.
Nuclear energy is increasingly becoming unpopular, particularly in Western
Europe, owing to antagonistic public opinion, whether this is justied or not. Also
the high front investment cost, long lead times and prospects of future legislation
renders nuclear energy unfeasible for private utility investors.
Renewables are generally weather dependent and as such their likely output can
be predicated but not controlled. The only control possible is to reduce the output
below that available from the resource at any given time. Therefore, to safeguard
system stability and security, renewables must be used in conjunction with other,
Electricity generation in a carbon-constrained world 121
controllable, generation and with large-scale energy storage. There is a substantial
cost associated with this provision.
Countries opt for energy security. Such security is enhanced by utilisation of
local resources, particularly local cheap coal, as is the case in North America,
South and East China. These countries will continue to rely on their local coal
resources, increasingly with clean-coal technologies, rather than resort to other
Future prospects of fossil fuel, nuclear as well as renewable energy for carbon-
free generation, including cost as well as technologies, are briey summarised in
Section 9.4.1.
9.4.1 Generation cost of power sources
In the EU, research was undertaken to assess the cost of the socio-environmental
damage associated with every type of electricity generation [5]. Such costs are not nor-
mallychargedtothe power producer andare not passedtothe consumer. But suchhid-
den costs are increasingly being taken into consideration by regulatory authorities in
their pursuit of sustainable strategies. These are the costs estimated to be borne by the
society in negative health impacts, resource depletion, global warming, etc.; an esti-
mation of the clear production costs, as well as the hidden social costs are given in
Table 9.3.
A relatively wide range of costs is indicated for each technology due to peculiar-
ities of individual projects, risks and discount factors and individual nancial costs
9.5 Clean fossil-fuel-based power technology
Programmes are underway to develop power plants of the future [6,7], using coal and
natural gas as the primary fuel, that:
are essentially pollution free;
nearly double the current generating efciency;
have the capability to produce a varied slate of co-products, such as chemicals,
process heat, and clean fuels.
Gasication technologies are an essential part of this effort because they provide
the means to vastly expand the clean fuel base to more-abundant and lower cost
resources (including biomass and wastes) and enable co-production of power and
high value by products.
Gasication breaks feedstocks down into basic constituents so that pollutants can
be readily removed and clean fuels or chemicals can be produced.
Resultant clean fuels can be used to power highly efcient and clean gas turbines,
fuel cells, and fuel cell/turbine hybrids.
Gasication concentrates the CO
constituent, which facilitates capture and
recycle or sequestration.
122 Economic evaluation of projects in the electricity supply industry
Table 9.3 Total cost of electricity generation
Item Power source Costs
Description Production
p kWh
p kWh
p kWh
1 Conventional coal red (with
FGD and CO
4 5 2.5 4.5 6.5 9.5
2 Oil-red (with CO
abatement) 5 6 2 3 7 9
3 Combined cycle gas turbine 1.2 3 0.6 1.2 1.8 4.2
4 Micro-combined heat and

5 Nuclear, AGR and PWR 3 3 0.15 0.15 3.15 3.15
6 Hydro 1.5 2.5 0.4 0.6 1.9 3.1
7 Tidal power 2 6 0.4 0.6 2.4 3.6
8 Onshore wind 2 3 0.1 0.1 2.1 3.1
9 Offshore wind 5 5 0.1 0.1 5.1 5.1
10 Landll gases 2 3 0.5 0.5 2.5 3.5
11 Municipal incineration 1 2 0.6 0.6 1.6 2.6
12 Biomass, eld, forest, straw 1.5 4 0.6 0.6 2.1 4.6
13 Import 1.7 1.7 0.15 0.15 1.85 1.85
14 Diesel 4 6 0.5 0.5 4.5 6.5
15 Photovoltaic 8 10 0.2 0.6 8.2 10.6
16 Hydro-pumped storage
17 Electrochemical storage
Source: Reference [5].
A clean-coal technology programme has sponsored integrated-gasication
combined-cycle (IGCC) projects, representinga diversityof gasiers andclean-up
systems that are helping to pioneer the commercial introduction of this next
generation power concept.
Gas separation membranes are important for enhancing the cost and performance
of technologies on many fronts, by offering the promise of displacing energy-
intensive, costly cryogenic and chemical means of separating out selected constituents
from a gas stream, such as oxygen, hydrogen, CO
, or pollutants.
Separation membranes have the potential signicantly to enhance the cost and
performance of gasication-based technologies.
Ion transport membranes for oxygen separation are in an advanced stage of
In addition to gasication applications, ion transport membranes open the pos-
sibility of combustion with oxygen rather than air to eliminate nitrogen-based
pollutants and to concentrate the CO
constituent, which enables capture.
Electricity generation in a carbon-constrained world 123
High-temperature ceramic membranes hold the promise of making a hydrogen-
based economy feasible and have immediate application to fuel cells, and fuels
and chemical production.
separation membranes have the potential to signicantly reduce the cost
of CO
capture, which is the most costly facet of the carbon sequestration
Advanced gas-turbine development is essential because gas-turbines will be a
mainstay in the power-generation industry for the foreseeable future, operating on
natural gas in the near- to mid-term and on gasication-derived synthesis gas in the
longer term. Advanced turbine systems programmes for the future aim:
(i) to improve the efciency and overall performance of the smaller gas-turbines
in electric-generation service that are subjected to highly cyclic loads, and
(ii) to link these gas-turbines to fuel cells to push efciency and environmental
performance even higher.
Fuel cells have the potential to revolutionise power generation because they:
(i) operate on a range of hydrogen-rich fuels (natural gas, methanol, and
gasication-derived synthesis gas),
(ii) represent a bridge to a hydrogen economy,
(iii) offer inherently high efciency and are essentially pollution free (emitting
water, CO
and heat),
(iv) lend themselves to distributed generation applications because of low emis-
sions and quiet operation (owing to few moving parts).
Distributed generation alleviates electricity transmission and distribution con-
straints (enhancing the reliability of electrical grids), enables combined heat and
power applications (boosting thermal efciencies upwards of 8090 per cent),
and offers an option to central-power generation.
Phosphoric acid fuel cells are offered commercially and are penetrating niche
markets, with efciencies of 40 per cent a few 250 kW units have already
been sold.
Second-generation, high-temperature molten carbonate fuel cell and solid oxide
fuel cells are poised to enter the market, with efciencies approaching 60 per cent
when operated in a combined-cycle mode that uses the process heat to produce
Fuel cell/turbine hybrids that has the potential to raise efciencies up to 70 per
cent by using the process heat from high-temperature fuel cells to drive a gas
turbine are under development. Fuel cell energy announced the start-up of a
250 kW molten carbonate fuel cell/capstone micro-turbine system, and a solid
oxide fuel-cell-based system is soon to follow.
Fuel cells are unlikely to take the power markets by storm. As long as a developed
hydrogen infrastructure is not available (and it may take decades), fuel cells are just
another fairly efcient means of converting gas into power and heat; no more, no less.
To succeed, manufacturing costs must rst drop to a level that allows prices barely to
exceed the $1000 kW
threshold. This may take quite some time.
124 Economic evaluation of projects in the electricity supply industry
9.6 Prospects for non-fossil-fuel power generation
9.6.1 Prospects for nuclear energy
Nuclear energy[8] still accounts for almost 16per cent of global electricityproduction.
However, for the last quarter of a century no nuclear plants were built in the US
and very few were built elsewhere. Public awareness and opposition to new nuclear
plants is no doubt the most signicant factor in the recent demise of nuclear power.
However, alarm about carbon emissions and the emissions-free character of nuclear
power rekindled hopes for a revival in such facilities. In the rst half of 2002, Finland
announced a decision to proceed with its fth nuclear reactor, the rst such decision
in Europe for a long time.
Nuclear power has many positive attributes that make it appealing to a balanced
electricity-generation mix. These include a very large potential energy resource,
demonstrated performance in maintaining very high levels of safe operation and
public and workforce health and safety, no atmospheric pollution, low and stable
fuel cost, and very high reliability. The substantial capital cost for new nuclear plant
capacity, however, remains a signicant, negative attribute of nuclear power.
This penalty cost of nuclear power has been aggravated by the rising efciency
and continuous fall in the cost of a modern CCGT plant. Recent cost assessment of an
Advanced Light Water Reactor (ALWR) plant put the average cost of construction at
about $1350 kW
. For new nuclear capacity to compete economically with natural-
gas-red plants, the nuclear plant would need to have achieved a construction cost of
possibly as low as $1000 kW
Signicantly higher natural gas prices, and/or the imposition of a hefty carbon tax
will improve nuclear power plants competitiveness. However, for nuclear, the poten-
tially large consequences of a beyond-design accident, and the long-term impacts
of radioactive waste are the main drivers that led to decisions for a moratorium
or the phasing out of nuclear power in some European countries. The problem of
proliferation also remains a critical issue.
9.6.2 Prospects for wind power
Wind power [9] is the most rapidly growing renewable energy source. Demand for it
is expected to increase by 13 per cent a year over the next 20 years.
The cost of wind power is high compared with fossil fuels, but declining capi-
tal costs and improved performance are likely to reduce generating costs. Wind is
expected to be competitive with fossil-fuel-based generation on the best sites on land
over the next decade. Figure 9.4 shows how electricity-generating costs for wind
power and fossil fuels may evolve in OECD Europe over the next 20 years.
Large land requirements and competition among different land uses could con-
strain growth. The intermittence of wind power and the unsightliness of wind turbines
could further limit site availability. The effects of intermittence must be taken into
consideration at the early stages of wind-power development, as the effects may
become more obvious with higher shares of wind in the electricity mix.
Electricity generation in a carbon-constrained world 125
2000 2010 2020
Cheapest fossil fuel alternative in
the base year equals 1
Cheapest fossil fuel
Onshore wind low
Onshore wind high offshore wind high
offshore wind low
Figure 9.4 OECD Europe electricity generating costs for wind and fossil fuels [9]
9.6.3 Prospects for solar cells
In 2001, the world solar-cell production [10] soared to 395 MW, up 37 per cent over
2000. This annual growth in output, now comparable in size to a new power plant,
is set to take off in the years ahead as production costs fall. Cumulative solar cell or
photovoltaic (PV) capacity exceeded 1840 MW at the end of 2001.
The cost of electricity from solar cells remains higher than from wind or coal-
red power plants for grid-connected customers, but it is falling fast owing to the
economies of scale as rising demand drives industry expansion. Solar cells currently
cost around $3.50 W
for crystalline cells, and $2 W
for thin-lm wafers, which
are less efcient but can be integrated into building materials. Industry analysts note
that, between 1976 and 2000, each doubling of cumulative production resulted in a
price drop of 20 per cent. Some suggest that prices may fall even more dramatically
in the future.
The European Photovoltaic Industry Association suggests that grid-connected
rooftop solar systems could account for 16 per cent of electricity consumption in
the 30 members of the OECD by 2010. If the costs of rooftop PV systems fall to
$3 W
by the middle of the present decade, as projections suggest, the market for
residential rooftop solar systems will expand. In areas where home mortgages nance
PV systems and where net metering laws exist, demand could reach 40 GW, or 100
times global production in 2001.
More than a million homes worldwide, mainly in villages in developing countries,
nowget their electricity fromsolar cells. For the 1.72 billion people not connected to
an electrical grid, solar cells are typically the cheapest source of electricity. In remote
areas, delivering small amounts of electricity through a large grid is cost-prohibitive,
so people who are not close to an electric grid are likely to obtain electricity from
solar cells. If micro-credit nancing is arranged, the monthly payment for PVsystems
is often comparable to the amount that a family would spend on candles or kerosene
for lamps. After the loan is paid off, typically in two to four years, the family obtains
free electricity for the remainder of the systems life.
126 Economic evaluation of projects in the electricity supply industry
PVsystems provide high-quality electric lighting, which can improve educational
opportunities, provide access to information, and help families be more productive
after sunset. Ashift to solar energy also brings health benets. Solar electricity allows
for the refrigeration of vaccines and other essentials, playing a part in improving
public health. For many rural residents in remote areas, a shift to solar electricity
improves indoor air quality. Photovoltaic systems benet outdoor air quality as well.
The replacement of a kerosene lamp with a 40 Wsolar module eliminates up to 106 kg
of carbon emissions a year.
In addition to promising applications in the developing world, solar energy also
benets industrial nations. Even in the UK, a cloudy country, putting modern PV
technology on all suitable roofs would generate more electricity than the nation con-
sumes in a year. Recent research surrounding zero-energy homes, where solar panels
are integrated into the design and construction of extremely energy-efcient new
houses, presents a promising opportunity for increased use of solar cells.
Continued strong growth suggests that the solar-cell market will play a prominent
role in providing renewable, non-polluting sources of energy in both developing
and industrial countries. A number of policy measures can help to ensure the future
growth of solar power. Removing distorting subsidies of fossil fuels would allow
solar cells to compete in a more equitable marketplace. Expanding net metering laws
to other countries and the parts of the US that currently do not have them will make
owning solar home systems more economical, by requiring utilities to purchase excess
electricity from residential solar systems. Finally, revolving loan funds and other
providers of micro-credit are essential to the rapid spread of solar-cell technologies
in developing nations.
9.6.4 The virtual power plant
Different generating facilities are likely to proliferate in the future. Beside conven-
tional plants, these include large wind farms, biomass power plants, district heating,
fuel cells, and PV plants. Connecting money energy suppliers together to form a
virtual power plant [11] poses a special challenge for information and telecommu-
nications technology. Numerous setpoint and actual values must be compared in a
decentralised energy-management system, automation units have to be controlled,
and forecasts of sun, wind and consumer behaviour must be obtained. Prospects for
a virtual power plant will also be discussed in later chapters.
9.7 References
1 JACKSON, K.: Moving towards an energy policy for the UK, Power Engineer-
ing Journal, April 2002, 16, pp. 5051
2 EDDIES, M.: Climate ConventionandKyoto Power Economics, February2001,
pp. 2325
3 ASCHENBRENNER, N.: Gentle Revolution, Siemens Magazine for Research
and Development, Spring 2002, pp. 5054
Electricity generation in a carbon-constrained world 127
4 ECOAL, World Coal Institute, 42, June 2002, p. 5
5 NEWTON, M., and HOIEWELL, P. D.: Cost of sustainable electricity genera-
tion, Power Engineering J., April 2002, 16, (2) pp. 6874
6 SMITH, C. M.: Technology and Fuels for Tomorrow, a lecture delivered in
the meeting of the CFFS Committee 18th World Energy Congress, Argentina,
October 2001
7 MCKEE, B.: Solutions for the 21st Century Zero Emissions Technologies for
Fossil Fuels Technology Status Report, IEA, Paris, May 2002
8 EPRI Journal Online: Nuclear Power in Americas Future, April 2002
9 ARGIRI, M., and BIROL, F.: Renewable Energy, Oxford Energy Forum, 49,
May 2002, pp. 35
10 FISCHTOWITZ-ROBERTS, B.: Sales of Solar Cells Take Off, Eco-Economy
Update 20028, Earth Policy Institute 2002
11 MULLER, B.: The Power of Small Step, Siemens Magazine for Research and
Development, Spring 2002, pp. 6163
Chapter 10
Economics of reliability of the power supply
10.1 Introduction
Reliability of the power systemis generally dened as the overall ability of the system
to perform its functon [1]. It can also be dened as the ability of the power system
to meet its load requirements at any time. Two distinct aspects of system reliability
are identiable: system security and system adequacy. System security involves the
ability of the system to respond to disturbances arising internally, whereas system
adequacy relates to the existence of sufcient facilities within the system to satisfy
the customer-load demand [2].
As mentioned in Chapter 1, reliability of the electricity supply is of paramount
importance. Interruptions (even transient supply problems) can cause serious nan-
cial and economical (social) losses. Electricity shortages can affect any country in
two ways: they can handicap productive activities and seriously affect consumers
welfare. From the productivity standpoint, electricity shortages discourage investors
by affecting production, increasing its cost, and requiring more investment for on-site
electricity production or standby supplies. For small investors, the cost of operation
is increased, since electricity from small private generation is more expensive than
public national supplies. Electricity interruptions at home also cause consumers great
inconvenience, irritation, loss of time and welfare [3].
To any economy, an unreliable power supply results in both short- and long-term
costs. Costs are measured in terms of the loss of welfare and the adjustments that the
consumers (such as rms), facing unreliable power supplies, undertake to mitigate
their losses.
Service interruptions may trigger loss of production, costs related to product
spoilage, and damage to equipment. The extent of these direct economic costs also
depends on a host of factors such as advance notication, duration of the interruption,
and timing. The latter refers to the time of day or season and to the prevailing mar-
ket conditions regarding the demand for the rms output. These direct costs can be
very high, particularly under conditions of uncontrolled load shedding and transmis-
sion and distribution outrages, i.e. sudden interruptions in service without advance
130 Economic evaluation of projects in the electricity supply industry
notication. In addition to the direct costs noted earlier, there are indirect costs to the
economy because of the secondary effects that arise as a result of the interdependence
between one rms output and another rms input.
Chronic electricity shortages and poor reliability of supply trigger long-term
adjustments. If a rms expectations are that shortages and unreliable service will
persist, then they will respond in one or more ways. The installation of back-up
diesel generator sets is the most common long-term adjustment taken by commer-
cial consumers and small industrial rms. It has been estimated that a substantial
amount of the total installed generating capacity in many developing countries
(in the order of 20+ per cent) is in the form of standby generation on customer
premises [4].
Shortages of electric power and supply interruptions occur because of either of
the following two reasons.
(i) Unreliability of the supply due to the non-availability of generating plants, or
breakdowns in the transmission and distribution system. Such unavailability can
occur in varying degrees in any power system in the world: system security.
(ii) Shortfalls of delivered electric power even under the best conditions of the
electric system. Such shortfalls usually occur in developing countries. Most of
these suffer capital shortages owingtoinadequate number of generatingfacilities
capable of matching the peak demand, and with limitations in the transmission
and distribution system, particularly to rural areas: system adequacy.
The ability of a power system to meet demand and deliver adequate electric energy to
the consumers, is termed above as system adequacy. To provide such adequacy and
to overcome supply shortages and interruptions, there is a need for investment. Most
investments in the ESI are meant to reduce the prospect of shortages, and maintain




Continuity (per cent)
99.98 100
Consumer surplus
Figure 10.1 Marginal utility and marginal cost of electric availability
Economics of reliability of the power supply 131
and improve reliability. Most of the shortages can occur as a result of the growth
in the demand, which necessitates generation extension and network strengthening.
However, and in spite of large investments, interruptions are inevitable. Costs of
improving continuity of the supply can be very high after a certain level of reliability.
As shown in Figure 10.1, such costs can increase at an exponential rate beyond a
certain level of reliability [5].
The function of the power system is to provide electrical energy as economically
as possible and with an acceptable degree of reliability and quality. Economics of
reliability tries to strike a reasonable balance between cost and quality of service. Such
balance varies from one country to another, just as from one category of consumers
to another. Most developing countries cannot afford the high costs of ensuring the
high reliability of supply, taken for granted in industrialised countries. Gradually,
however, quality of supply is improving in developing countries.
10.2 The value of reliability
By value of reliability, we mean the estimation (in monetary terms if possible)
of the benets and the utility derived by the consumer from achieving (or improving)
a certain level of availability of the supply. The cost of unreliability over a certain
period is the social cost (nancial and economic) suffered by consumers as a conse-
quence of supply interruption during that period. Costbenet analysis of reliability
economics in planning of the power systemhas not advanced in the way it has in some
other public services, e.g. transport. This is because of the great difculty of obtain-
ing comprehensive assessment of the reliability of supply from the generating system
down to the consumer terminals. Even more difcult is the evaluation of consumer
nancial and economical loss, and the inconvenience due to interruptions [6].
The electricity tariff does not reect the benets that consumers (the economy)
derive from the existence of the electricity supply. In Figure 10.1, the tariff, if it is
xed at a long-run marginal cost, is equal to CA. What the consumer pays for is the
annual quantity of consumption multiplied by the tariff (area OECA). The benets are
the entire area under curve (B) and to the left of CA. This is much higher than what is
paid. The difference is called the consumer surplus, which is the extra benet that the
consumer derives out of the presence of the supply over what is paid in tariffs, which
is usually substantial. The consumer loss of utility due to interruption is depicted by
area ACDE.
It is possible, however, to assess the contribution of different schemes towards
the continuity of supply and to choose the one with the maximum contribution within
economical cost. The problemstill remains of what is the economical cost? Because
of these difculties, empirical design rules and national standards for supply security
have been set to guide and limit the planners, without resorting into actual monetary
valuation of reliability benets. In a few countries, however, monetary values have
been xed for evaluating the cost of loss of supply. These values are utilised to evaluate
cost of interruptions and compare these with the system strengthening cost, in order
to justify its execution.
132 Economic evaluation of projects in the electricity supply industry
What the planner would aimat is not a completely uninterruptible supply, the cost
of such a system would be prohibitive as shown by curve (A) of Figure 10.1. The aim
should, however, be the point of optimum reliability point C in the gure. Point C is
the intersection of the reliability marginal cost curve to the electricity supply industry
(curve (A)) with the marginal cost of interruptions to the consumer (curve (B)). The
intersection point is where the optimumreliability is obtained. It is where the marginal
utility of the extra increment of reliability improvement to the consumer is equal to
the marginal cost spent in achieving it by the supply industry.
It is possible to draw curve (A) over a wide range. This curve, which can be
evaluated by modelling, is the least-cost system strengthening scheme as chosen
from many schemes, which would lead to the same reliability but involve higher cost.
It is, however, very difcult to draw curve (B). It is now possible, through studies
and consumer surveys to obtain information and build tables of interruption cost data
applicable to certain categories of consumers and certain areas [7]. Such data are
valuable in estimating the value of reliability to assist in costbenet analysis for
system strengthening.
10.3 Reliability in system planning
In order to understand the value of this approach, it is advantageous to reviewthe exist-
ing methods that guide reliability planning and are applied by most of the electricity
supply utilities worldwide. These can be summarised as follows [5]:
empirical planning rules,
supply design standards,
simplied costbenets analysis, and
detailed nancial and economic evaluation.
The rst three methods will be discussed in Sections, and the fourth
method will be discussed in detail in Section 10.4.
10.3.1 Empirical planning rules
In this case, the planner, based on his experience and practice in dealing with similar
situations, decides on the desired reliability level. This is achieved through the evalu-
ation of the importance of the system and network and correspondingly the extent of
redundancy to be incorporated, taking into account the following: the part of the sys-
tem it is dealing with, voltage level and nature of the network, number and category
of consumers, nancial constraints, and past reliability records and past experience
in handling a similar situation.
Almost all systems that do not have drawn out and written supply design standards,
or probabilistic planning, employ such criteria. The empirical rules for generation
involve a percentage reserve-margin method, without a loss of load expectation
(LOLE) calculation; or for a small system, a rmgenerating capacity with the biggest
set(s) out-of-commission. For the main network the n 1 rule is employed, which
Economics of reliability of the power supply 133
means that the loss of a main line from n parallel lines, or a transformer of n trans-
formers, should not affect continuity of supply, with more emphasis being placed on
important networks. In the distribution, and lower-voltage networks, rules of thumb
are employed in accordance with the consumer category and investment constraints
mentioned earlier.
10.3.2 Supply design standards
Supply design standards are a step forward from the empirical approach, where the
amount of past experience, performance, economical limitations and individual sep-
arate rules are reduced to a set of detailed guidelines for utilisation by planners to
reliably design the system.
In generation, this involves a LOLE target, which stipulates that in any year the
probability of capacity shortage should not exceed a certain value; usually a fraction
of a day. Correspondingly, plans are drawn out in advance for the generation system
strengthening so that LOLE would not exceed a certain standard. In the network,
consumer groups and supply areas are classed in accordance with their demand, the
minimum number of circuits available, and the target time for restoration of supply
is specied. For interruption duration not to exceed a certain level, the network may
need strengthening.
10.3.3 Costbenet analysis
Generally, not all costbenet analysis of the power systemshould necessarily involve
monetary valuation of the cost of interruption. An increasing amount of work is being
undertaken to evaluate the cost of different schemes and the probable amount of
interruption. Further engineering judgement is used to choose the right plan, within
the constraints mentioned, utilising empirical rules.
A simple actual example commonly encountered is that of choosing the method
of protection of rural single feeders (Figure 10.2). Three methods are discussed
and costed: expulsion fuses (EF), autoreclose circuit breakers (AR) and AR with
automatic-sectionaliser (AS), in the middle of the line. The cost and predicted con-
tinuity performance of these schemes when applied to a particular rural network are
summarised in Table 10.1.
Costbenet engineering judgement can now be applied. The employment of
EF with an expenditure of only 500 on network protection will involve 12 000

5100 kVA p.m. transformers
Figure 10.2 Rural network protection scheme
134 Economic evaluation of projects in the electricity supply industry
Table 10.1 Rural network protection costs
Scheme Protection Cost Probable cons. h per consumer
h per annum
1 Expulsion fuses 500 24 h 500 cons. = 12 000 24
2 Autoreclose 3500 4 h 500 = 2000 4
3 Autosectionalise 5500 1 300 +4 200 = 1100 2.2
Note: probable consumer-hours (cons. h) interrupted per annum are calculated based on
experience of annual interruption duration for such networks.
consumer-hours lost and an interruption of 24 h per consumer per annum (plus main
network interruptions). An expenditure of 3500 will save 10 000 consumer-hours;
an extra 2000 investment can still reduce interruptions by a further 1.82.2 h and
consumer-hours lost by 900. The problem is which plan to choose? The estimation
of interruption length is obtained through experience in operating such systems.
It is doubtful if any system planning will accept scheme 1 in Table 10.1 (except
if there is acute capital shortage). The question is whether the extra cost of scheme 3
justies the expenditure. In a mature supply the engineer will empirically decide that
the 4 h are excessive and its reduction to 2.2 h justies the expenditure.
Proper costbenet evaluation involves valuing the social cost of interruption
to the consumers over the next 2030 years, also the cost of the fuses repair, the
AR and AS maintenance over the same period, and discounting these costs to their
present value. If with scheme 2 the present value of the social cost of interruptions
plus the discounted cost of maintenance is higher than 3500, then scheme 3 is
chosen. Alternatively, in case of a lower cost, then scheme 2 is adopted. If the cost of
interruptions is much higher, then a more reliable supply should be provided through
an alternative source. This, of course, necessitates detailed evaluation of the cost to
the consumer of aborted energy (curve (B) in Figure 10.1).
One interesting feature of this simple example is how the marginal cost per
consumer-hour saved, increased considerably after making the rst step, from 0.30
to 2.22. Thus, the dominant feature is the accelerating cost of higher reliability
(curve (A) in Figure 10.1).
10.4 Detailed nancial and economic evaluation
10.4.1 System adequacy and economics
The power system consists of three functional zones: generation facilities, transmis-
sion facilities and distribution. From the reliability point of view, it can be looked at
in three hierarchical levels. The generation facilities, the generation and transmission
and the third hierarchical level of the generation, transmission and distribution [1].
Economics of reliability of the power supply 135
The adequacy of the generating system is the most important aspect in system
planning to ensure the system-function performance. A shortage in the ability of gen-
erating facilities to meet demand can cause serious and sometimes widespread supply
interruptions, particularly during peak demand. This leads to immense nancial
losses, inconvenience and disturbance to consumer welfare. Therefore, the adequacy
of generation is paramount in power-system reliability. Adequacy of the bulk trans-
mission network is also important. However, its reliability is usually much higher than
that of other parts of the electrical power system. Although faults and inadequacies in
this network can cause serious interruptions, they are less frequent than those of the
other facilities of the system. Distribution system disturbances and inadequacy cause
only localised interruptions, which are less serious than generation and transmission
10.4.2 Assessment and economics of generation adequacy
Sufcient reserve is essential to ensure the adequacy of the generating system. This
reserve was determined, in the past, by methods such as ensuring that the generating
systemhad enough percentage reserve, usually not less than 1525 per cent of system
peak, depending on the size of the system, in order to meet maintenance requirements,
unscheduled breakdowns of generating facilities or higher demand than anticipated.
In small systems, generation reserve was assessed to be equal to the largest or the
two largest sets out of commission. Such deterministic methods cannot ensure the
optimisation of investment in the system nor can they determine to a fair degree
of accuracy the extent of system adequacy, and that this is the economically optimum
adequacy. Correspondingly, simulation utilising probabilistic methods, which can
more faithfully predict system performance and assist in the economical evaluation
of investment, have become common in planning most large generating systems. The
introduction of new generation facilities into the system reduces expected shortages
and has system results that affect the whole economics of generation and the cost
per unit of electricity produced. Such system effects can only be assessed through
probabilistic simulation techniques.
The most widely utilised methods of assessing adequacy of generation
are: the loss-of-load expectancy (LOLE) index, percentage energy loss index, and
the frequency and duration method. These indices are used to assess probabilis-
tic generation adequacy by convolution of the generating capacity model with the
load model [8].
Loss-of-load expectation (LOLE) method
The LOLE may be the most widely used probabilistic index for generation reliability
assessment. It is based on combining the probability of generation capacity states
with the daily peak probability so as to assess the number of days during the year in
which the generation system may be unable to meet the daily peak:

136 Economic evaluation of projects in the electricity supply industry
where n
is the number of occurrences of peak demand L during the year, and A
the cumulative probability of being in capacity state j, such that C
L > C
The reciprocal of the above equation is the LOLE in years per day. This means the
probable number of years, or fraction of a year, during which the generation system
will be unable to meet the peak demand of that day.
The LOLE index has gained recognition because it provides a probabilistic gure
that can be computed and employed in systemplanning. It combines a generation and
a load model. It is relatively simple to compute, understand and apply. However, this
index suffers from the following shortcomings.
It gives no indication of the extent of load shedding in mega watt (MW) or percent-
age wise, mega watt nor does it give any indication of its duration or frequency
regarding the average consumer, which is what reliability assessment should be
mainly concerned with.
The LOLE, in days per year, mainly indicates the number of days in the year in
which the generating systemwould not be able to meet the load. The frequency of
load shedding may be higher than this gure in case of double peaked daily load
curves and in systems that employ units with high failure rates but short repair
Since such an index is not capable of assessing the actual damage, it is not very
useful for comparing the reliabilities of different utilities or national systems,
particularly if they have different shapes of the load curve and peak durations.
The above arguments, particularly the rst, have been recognised by the many users of
this index. However, it is argued that for the same system, the use of the LOLE index
would be adequate and correct for investigating different expansion plans and annual
maintenance scheduling. This is only correct if the duration of peak demand is static
over the years of study. This is not the case in many systems, with the continuous
increase in the middle of the day load being experienced in most cases, particularly
in developing countries.
To give an example, suppose that for a certain system with a typical daily load
curve and annual load duration curves A and a respectively in Figure 10.3. The
LOLE would be associated with the probably curtailment of the portion of the energy
higher than the line C. If over a few years, the shape of the load curve changes to
that of B and b while the LOLE is maintained constant, then the probable amount
of energy curtailment, area c +c

, increases faster than the growth of peak demand.

This signies a disutility to the consumer and an actual increase (probably small) in
the unreliability of supply, which the LOLE cannot measure and defeats the purpose
of maintaining the LOLE constant.
The effects of the change in the shape of the load curve and pattern of consumption,
although they take place slowly over years, may change signicantly fromone season
to another in the same year.
Besides the signicant arguments against the LOLE mentioned above, it can be
misleading in long-term planning and annual maintenance scheduling in systems of
non-stationary load curves where signicant changes in the duration of the peak load
are expected to be encountered between seasons and over years.
Economics of reliability of the power supply 137
Time Time
Figure 10.3 Effect of change of load curve on electricity curtailment
Frequency and duration method with a load model
The theory of the frequency and duration analysis of the generation states with a load
model is detailed in Reference [8].
The generation frequency and duration approach, when coupled with the proper
load model, will lead to the computation of a comprehensive reliability data. It will
indicate the probable existence of all possible negative margin states, their frequency
of occurrence, cycle time and mean duration.
However, the model does not yield a single reliability index. Two indices are
calculated: an availability index and another frequency index. Here also the frequency
index is of similar value to that of the LOLE and the sound arguments against its
application for system expansion and medium-term operation can be applied. The
availability index will account for the duration of load shedding but not its extent and
This was recognised by the developers of this method and the following index
of percentage energy loss (PEL) [9] was suggested as being more representative of
the actual reliability of the system for planning purposes.
Percentage energy loss (PEL) index
The method involves the generation capacity states availability table and the daily
load curve. The probable energy curtailment, during one year, divided by the energy
requirement of the load, and multiplied by 100, yields the PEL index:
probable energy curtailment
energy requirement
The probable energy shedding is obtained by combining the generation states avail-
ability table with the segments of the load curve. By summing up all load segments,
the probable energy curtailment will be computed.
The percentage energy loss index comes nearer than any other single index to
assessing the true reliability of generation, because it reects the ratio of energy
138 Economic evaluation of projects in the electricity supply industry
curtailment (disutility) to the consumer to his consumption (utility). Hence, it can
measure the amount of inconvenience and loss to the consumer, which is the principal
concern of any reliability criterion. However, it also suffers from the fact that it is not
useful in a dynamic load curve. If the generation expansion scheme is aimed towards
maintaining the index constant, then with the load factor improvement with time,
owing to an increase in base load (say by an increase in off-peak space heating), the
amount of energy permitted curtailment, which usually occurs during peak hours,
would increase in proportion more than the growth in peak demand. This indicates
deterioration in the actual reliability of the supply and an increase in consumers
disutility and inconvenience, which defeats the purpose of maintaining the index
We have demonstrated the computational methods of various reliability indices
that are widely utilised for power system projects planning. What is important is how
to use themintelligently. This calls for a better assessment of the social costs of power
system unreliability, particularly those caused by the generating system.
10.5 Financial and economic evaluation of
quality of electrical power
The cost of electrical power interruptions [10] to facilities utilising electricity has
been detailed earlier. However, these facilities can be sensitive to a wider range of
power quality disturbances other than just outages that are counted in utility reliability
statistics. In the newdigital economy, momentary interruptions or voltage sags lasting
less than 100 ms can have the same impact as an outage lasting many minutes.
To overcome the damage caused by these transient disturbances it is essential
sometimes, for certain facilities (like banks, data and customer service centres), to
invest in technologies for equipment protection and improving power quality. Such
investments can be very high, and correspondingly a costbenet analysis is required
before embarking on them.
Such a costbenet analysis will have to:
analyse the power system quality performance,
correspondingly estimate costs associated with power disturbances,
look into technological solutions in terms of effectiveness and cost, and
perform the costbenet analysis.
Voltage sags and monetary interruptions have most important impacts on performance
of facilities. There is equipment that is usually sensitive only to magnitude of voltage
variation, others are sensitive to both magnitude and duration of an r.m.s. variation.
IEEE Standard 1159 denes voltage sags lasting between 0.5 and 30 cycles as
instantaneous, those lasting between 30 cycles and 3 s are identied as momentary,
and those lasting between 3 s and 1 min are dened as temporary. In addition to
magnitude and duration, it is often important to identify the number of phases involved
in the sag.
Economics of reliability of the power supply 139
The costs associated with sag events vary widely according to facilities and market
conditions. Such costs can be product-related losses, labour-related losses and other
costs like damaged equipment and loss of income. Costs will vary with magnitude,
duration and frequency of power quality disturbance.
Cost of power quality improvement technologies depends on the alternative cat-
egory involved, its investment cost as well as operating and maintenance cost. For
small control protection (less than 5 kVA) CUTS, UPS, and dynamic sag protectors
are employed. For machine protection (up to 300 kVA): UPS, ywheel as well as
dynamic sag corrector are employed. For large facility protection in the 210 MVA
range, beside the UPS and ywheels, dynamic voltage regulators as well as static and
dynamic transfer switches are employed.
To perform the required economic analysis the solution effectiveness of each
alternative must be quantied in terms of the performance improvement that can be
achieved. Solution effectiveness, like power quality costs, typically will vary with the
severity of the power quality disturbance, and the type of activity.
Once the costs of the quality improvement technologies and their effectiveness
have been quantied, a normal costbenet analysis exercise, like the ones explained
in this book, have to be undertaken before decision making.
10.6 Evaluation of investment in generation
Optimisation of investment in the generating system is important for the economics
of the electricity supply industry. Generation facilities constitute almost two-thirds of
all new investments in the electric power system and the vast majority of the oper-
ational cost. The losses due to their unavailability are widespread in contrast to the
network problems, which have localised consequences. Therefore it is essential to
optimise these to ensure the economic as well as the technical adequacy of the power
The most important points to be addressed when investing in power generation
are as follows.
Selecting the location many technical and economical considerations govern
selecting the location (fuel availability, cooling water requirements, availability
of land, proximity to the load centre, conguration of the transmission network
and environmental considerations).
Timing this is inuenced by the criteria for generation adequacy as well as load
growth prospects and lead time for the new facilities. Such issues were addressed
in Chapters 5, 6 and 7.
Type, size of the new facilities and fuels there are many and increasing types
of new generation facilities (conventional thermal units ring pulverised coal or
other fuels, nuclear, hydro, gas-turbines in a simple or combined cycle, etc.).
What is important is not only the type of facility and fuel consumed, but also the
optimum set size that ts economically, to the growing load curve, in order to
reduce risk.
140 Economic evaluation of projects in the electricity supply industry
There are several established algorithms to assist in generation planning and its
economics. All of these are based on a decision-making framework expressed in
economic terms aiming to schedule least-cost investments for power generation
expansion. Some of these are Wein Automatic System Planning (WASP) Model [11]
and the UNIPEDE Model [12]. Such models, however, fall short of achieving proper
nancial and economic evaluation of generating planning because of weaknesses in
the system adequacy criteria that they utilise, as explained above. It is necessary
to undertake detailed nancial and economical evaluation, with proper economic
adequacy criteria.
10.6.1 Valuing cost of interruptions
The cost of electricity to a consumer, i.e. the consumers evaluation of the worth of
the electricity supply (while ignoring consumers surplus), is equal to payments for
electricity consumed plus the economic (social) cost of interruptions.
Supply interruptions cause disutility and inconvenience, in varying degrees and
in different ways, to different consumer classes, domestic, commercial and industrial.
The costs and losses (L) of these interruptions to the average consumer are a function
of the following:
dependence of the consumer on the supply (C)
duration of the interruption (D)
frequency of its occurrence in the year (F)
time of the day in which it occurs (T )
L = (D
, T
) C,
where d, f and t are constants, but vary from one consumer category to another.
It is becoming increasingly necessary to assess the cost of interruptions to con-
sumers in monetary terms and to use this assessment as an input in the project
evaluation to arrive at the system plans that minimise total overall nancial and
economic cost to the utility and the consumer (payment in tariffs plus the cost of
interruptions). Many problems are encountered.
Consumer cost is not only a function of the frequency and duration of the inter-
ruptions, but also the day and the time of the day in which they occur as well
as consumers category and expectations. An interruption that occurs after mid-
night and causes a considerable amount of energy curtailment of off-peak heating
may pass unnoticed by the consumer, while a similar interruption that involves
much less energy during peak hours and household maximum activity will cause
enormous consumer irritation and inconvenience.
Consumer costs due to interruption are not a linear function. It is highly likely
that they will be similar to curve (B) in Figure 10.1, i.e. the marginal utility of
an extra incremental improvement in reliability decreases slightly as reliability
Economics of reliability of the power supply 141
Generation shortages usually occur during peak hours where system demand is
highest and value of electricity is most important to consumers. Most network-
caused interruptions are random in occurrence and can happen any time during
the day. Therefore interruptions caused by generation shortages are more costly
to consumers than network problems.
The amount of energy curtailed is no indication of the value of electricity to
consumers. The value of operating little-energy consuming sensitive machinery
for a rm, or TVand light to a household, far out-weights the value of high-energy
consuming apparatus and machinery, at least for short interruptions.
Until now and in most countries, the determination of the level of reliability is based
on experience, judgement and also the availability of funds to invest in standby plant
and redundant systems. Increasingly in Europe and North America, a lot of techniques
are used to assess the nancial losses to consumers as a result of supply interruptions,
i.e. the worth of reliability in monetary terms. There are many ways to assess such
costs; most of these can be obtained from the established techniques of consumer
surveys. The purpose of consumer surveys is to assess consumer willingness to pay
(WTP) for extra reliability of supply. Fromconsumer surveys it is possible to drawout
consumer damage functions (consumer cost). These reect the costs that consumers
of different categories are likely to endure as a consequence of supply interruption,
based on their demand, category of use, and the frequency and duration of these
interruptions. Such costs are weighted with regard to the respective energy utilisa-
tion in the district (or country). The weighted costs are then summed to provide the
total cost for the district for each specied duration. These are termed as composite
consumer cost function for the district or country. From these the total annual cost
of interruptions is computed and compared with the energy curtailed to arrive at an
average economic cost per kWh of electrical energy curtailed [13,14].
There are some uncertainties that surround such an approach, but it is closer than
anything else in assessing the actual cost to consumers of supply unreliability. This
method can be rened further to assess a rate for generation interruptions and a differ-
ent rate for network interruptions, taking into account that most generation shortages
occur during peak hours. Therefore, energy curtailment at peak times is more valu-
able than that resulting from transmission and distribution network problems, which
are random in nature. The total value of the electricity to a consumer is the amount
of the payments made by the consumer, in the form of tariffs, plus the social cost of
electricity interruptions, as valued by the consumers willingness to pay.
Economic cost of electricity = (energy consumed in kWh tariff) + social
cost of energy interruptions (kWh interrupted average cost to consumer per kWh
10.6.2 Incorporating reliability worth in generation planning
The economic planning of electricity production will try to minimise this economic
cost by striking the right balance between electricity production cost (tariff) and
supply continuity, as detailed in Figure 10.4.
142 Economic evaluation of projects in the electricity supply industry
Consumer interruption cost
Total generating
system cost
Fuel and other
operational cost
Investment and other
fixed costs
optimum continuity
Continuity (per cent)
Figure 10.4 Total cost of the power system including cost of interruptions
Such a calculation will indicate the percentage continuity gure that minimises
total generation system cost (including interruptions cost), and correspondingly the
amount of percentage reserves required to attain such a continuity.
This cost factor is useful for power system planning in order to minimise the
system cost to consumers. In such cases, a generation simulation model like that of
Figure 10.5 is utilised to assess the expected (cost of generation at a future year [cost
of electricity (xed and operational) + cost of interruptions to the consumers). Sets
are added until the optimum continuity is obtained. This will occur when the above
sum is at a minimum. Such simulation is carried out for many years into the future,
utilising different generation-extension scenarios, in order to plan a programme for
generation strengthening over time.
The same approach applies to the planning and the timing of network strengthen-
ing, where the economic cost of electricity supply to a particular area is equal to the
cost of energy utilised by the area plus the cost of interruption to the consumers in
that area, as caused by network problems. Anetwork-strengthening exercise is carried
out to assess the economic cost of each new network-strengthening conguration in
order to compute the discounted net benets of each scheme. The net benets in this
case will be the discounted reduction in consumer economic cost due to interrup-
tions plus reduction in losses minus the discounted cost of the network-strengthening
scheme (including any other system cost). If these net benets are positive, then the
strengthening scheme is undertaken. It has to be recalled that the discounted reduc-
tion in consumer economic cost is equal to the discounted amount of reduced energy
curtailment in kWhs multiplied by the average economic (social) cost of each kWh
Economics of reliability of the power supply 143
Read: load data
Existing sets and future expansion scenario
set details
(Repeat over all possible expansion scenarios)
For year y
(i) Compute operation costs
(ii) Compute investment costs for year ( y)
(iii) Compute energy curtailment (kWh
multiply by social cost per kWh
Total annual system cost in year y
Sc =(i) + (ii) and (iii)
no. of sets
j =j+1
Sc <Sc1
y =Y
Y=study period
y =y +1
Increase values of load by
one year
j =list of existing system a
and new sets
Carry out a PV of Sc
over years Y
write: PV costs of system
costs of expansion
list future set sizes
and commissioning date
Figure 10.5 System expansion plan (to minimise total system cost (operation +
investment +interruptions))
Many attempts were made to assess the economic cost of each kWh curtailed
in order to utilise this in system planning. In the 1990s, the UK electricity supply
industry assessed the value of lost load (VOLL) to be 2.345 kWh
[15]. The VOLL
is dened as the value that customers place on the amount of energy they would have
consumed during a supply interruption. A study [13] in North America in 1985,
based on the computation of consumers damage function, assessed this to be equal
to almost $5 kWh
(3.00), which is not very different. However, such values are
much lower for developing countries, where electricity is valued by the consumer
at a lower value owing to their limited WTP, and the shortage of funds, particularly
investment prospects in foreign currency, necessities that lower levels of reliability
be tolerated.
It has to be realised that such values are based on certain supply continuity
standards and consumer expectations. These are likely to change with changes in
continuity as demonstrated by curve (B) in Figure 10.1.
144 Economic evaluation of projects in the electricity supply industry
10.7 References
1 BILLINGTON, R., and ALLAN R. N.: Power-system reliability in prospective
(Applied Reliability Assessment in Electric Power Systems, IEEE Press, 1991,
pp. 16)
2 BILLINGTON, R., and ALLAN, R. N.: Power systemreliability in perspective,
Electron. Power, J. Inst. Electr. Eng., March 1984, pp. 231236
3 KHATIB, H., and MUNASINGHE, M.: Electricity, the Environment and Sus-
tainable World Development, World Energy Council, 15th Congress, Madrid,
4 Power Shortages in Developing Counties US Agency for International Devel-
opment, report to Congress, March 1988
5 KHATIB, H.: Economics of reliability in electrical power systems, (Technicopy
Ltd., England, 1978)
6 MUNASINGHE, M.: The economics of power system reliability and planning
(World Bank Research Publication, 1979)
7 BILLINGTON, R., WACKER, J., and WOJCZYNSKI, E.: Comprehensive
bibliography on electrical service interruption costs, IEEE Trans., June 1983,
PAS-102, (6), pp. 18311837
8 IEEE Committee: Bibliography of the application of probability methods in
power system reliably evaluation, IEEE Trans., 1984, PAS-103, pp. 275282
9 BILLINTON, R., WACKER, G., and WOJCZYNSKI, E.: Customer damage
resulting from electric service interruptions, Canadian Electrical Association,
R&D project 907, U131 report, 1982
10 MCGRANAGHAN, M.: Economic Evaluation of Power Quality, IEEE PER,
February 2002, 22, (2), pp. 812
11 Senior Export symposium on Electricity and the environment, Helsinki,
May 1991 (International Atomic Energy Agency (IAEA), Vienna 1991)
12 Electricity generating costs for plants to be commissioned on 2000, UNIPEDE,
Paris, January 1994
13 BILLINGTON, R., and OTENG-ADJEI, J.: Cost/benet approach to establish
optimum adequacy level for generating system planning, IEE Proc. C, March
1986, 135, (2)
14 BILLINGTON, R., OTENG-ADJEL, J., and GHAJAR, R.: Comparison of two
methods to establish an interrupted energy assessment rate, IEEE Trans., August
1987, PWRS-2, (3)
15 ALLAN, R. N., VOLL-fact or ction?, Power Eng. J., February 1995, 9, (1), p. 2
Chapter 11
Electricity trading
11.1 Introduction
The energy sector is undergoing a major transition worldwide [1,2]: competition,
restructuring, privatisation and regulation are at the core of the current revolution,
driven in part by newtechnological developments and changing attitudes towards util-
ities. The objectives of these reforms are to enhance efciency, to foster competition
in order to lower costs, to increase customer choice, to mobilise private investment,
and to consolidate public nances. The mutually reinforcing policy instruments to
achieve these objectives are the introduction of competition (supported by regula-
tion) and the encouragement of private participation. An international approach for
It includes the following.
The corporatisation and restructuring of state-owned energy utilities.
The separation of regulatory and operational functions, the creation of a coher-
ent regulatory framework, and the establishment of an independent regulator to
protect consumer interests and promote competition.
The vertical unbundling of the electricity industry into generation, transmission,
distribution, and trade (services).
The introduction of competition in generation and trade and the regulation of
monopolistic activities in transmission and distribution.
The promotion of private participation in investment and management through
privatisation, concessions, and new entry.
The reduction of subsidies and rebalancing of tariffs in order to bring prices in
line with costs and to reduce market distortions.
One of the most signicant features of the electricity supply industry in recent
years has been the emergence of electricity trading in liberalised electricity mar-
kets; this also fostered risk management practices. Such activities, particularly risk
management, are unimportant in regulated markets with xed prices; it is only in lib-
eralised markets where prices are charged in accordance with supply and demand and
future expectations with possible price volatility that such activities ourish. This is
146 Economic evaluation of projects in the electricity supply industry
enhanced by the introduction of customer choice. Such features manifest themselves
to a varying degree in various liberalised markets; however, they are prominent in the
US where prospects for electricity price volatility exist, owing to supply and delivery
restrictions, more thaninthe UKandEurope where there are abundant reserve margins
and strong interconnected transmission networks. Market players include generators
producing electricity, suppliers who buy electricity to sell on to groups of consumers,
traders and marketers who do not own generating assets but have active roles in the
market place, and other players who provide, for example, risk management, hedging
and brokerage.
Power marketing (or trading) refers to any number of nancial and/or physical
transactions associated with the ultimate delivery of a host of desirable energy-
related services and products to wholesale and, increasingly, retail customers. Power
marketers, those engaged in such trade, however, need not own any generation, trans-
mission or distribution facilities or assets. They rely on others for the physical delivery
of the underlying services. Moreover, power marketers operate primarily as con-
tractual intermediaries, usually between one or more generators and one or more
The physical nature of electricity does not allowa true spot market (instant pricing
and delivery) so nancial transactions must be scheduled some time in advance of
physical delivery, with pools or power exchanges thus substituting for a true spot
Electricity market trading is quite different from commodities trading (or other
forms of energy trading) because of the nature of electricity it cannot be stored, its
availability must be instantaneous and absolute, as well as the technical complexities
of the expertise, knowledge and planning capabilities that only power engineers can
provide. For an electricity market to performsuccessfully, two types of expertise must
a high level of technological expertise in the domain of power engineering, and
nancial and business expertise allowing market trading.
Only after the power engineers have set the parameters for physical delivery, both
short term and into the future to meet foreseeable conditions, can the nancial market
trading element of the electricity markets come into play.
11.2 Electricity trading worldwide
For regulators, the creation of trading exchanges can offer the chance to build a truly
open and competitive market, guided by a global knowledge base of the successes and
failures of other exchanges in other industries around the world [3]. It is interesting
that the Financial Services Authority (FSA) will regulate energy trading in the UK,
rather than the industry regulator (OFGEM), a trend that will continue in Europe.
Energy exchanges enable the development of the wholesale business. In addition
to the trading of physical quantities, future markets are created making extensive
use of nancial products. Many exchanges offer multi-energy (i.e. electricity, gas, and
Electricity trading 147
oil) services, sometimes extending to other commodities as diverse as metal, pulp,
and paper.
The number and nature of players will evolve as the electricity market continues
to open and the liquidity of exchanges increases. It is foreseeable that electricity
trading will occur increasingly over the Internet in the coming years. Some projections
anticipate that, by the year 2004, approximately 11 per cent of total electricity and
about 25 per cent of natural gas sold in the US will be sold online.
There is a lot to be gained for all parties through these newmarkets. But it can be a
complex process, and companies should evaluate participation in a trading exchange
against the current market trends, the drivers in energy markets and the broader
developments in nancial and commodity trading.
Such considerations are unlikely to lessen the pace at which trading exchanges in
the energy sector are growing. Instead, market forces, technology, and legislation will
shape the new exchange landscape, creating an environment in which competition
increases rapidly and consolidation occurs. It is vital that this moulding inuence is
allowed to continue, as for a market to successfully move to a deregulated mode, the
basics such as maintaining an adequate balance of regional supply and demand must
be established.
Across the world, competition in energy markets has driven the development of
wholesale energy trading. There is an enormous variety in the speed and willingness
of markets to deregulate, from country to country, and even from state to state. Many
countries already have fully competitive and mature markets while other countries
still do not plan to deregulate their gas and electricity industries.
The US is the most important market for electricity trade; this market and its
development will be explained in Section 11.2.1, and then the UK and other markets
will be discussed in Sections
11.2.1 Electricity trading in the US
During the past decade or so, and particularly since 1992, the growth of electricity
marketing, particularly in the US has been phenomenal [1]. The year 1978 saw the
passage of the Public Utilities Regulatory Policy Act (PURPA), which opened the
power-generation sector to new players, mostly independent power producers (IPPs).
For IPPs to prosper and succeed they needed access to the national transmission
network in order to deliver their product to large consumers. This was provided for
in the Energy Policy Act of 1992, and was supported by two signicant orders, in
1996, in which the US Federal Energy Regulatory Commission (FERC) spelt out the
modalities for implementations on how an open access transmission system would
work in practice. More specic orders were issued in 1999 and 2001 encouraging
and calling for the creation of regional transmission organisations (RTOs). Such
major milestones in the development of the liberalised US electricity markets are
summarised in Table 11.1.
In North America, the electricity market is deregulating at a variable pace. In the
US, each state moves forward independently from the others. California, which is
further along the process, has experienced signicant difculties (see Section 11.2.4)
148 Economic evaluation of projects in the electricity supply industry
Table 11.1 Electricity milestones: major laws with signicant impact on US
electricity markets
1935 Federal Power Act
Created the FERC and established principles for regulating wholesale electricity pricing.
1978 Public Utility, Regulatory Policy Act (PRUPA)
Allowed independent power producers (IPPs) to ourish.
1992 Energy Policy Act (EP Act)
Introduced the premise of a non-discriminatory open access transmission network.
1996 FERC Orders 888 and 889
Spelt out FERCs long-standing policy on how an open access transmission system would
work in practice; Order 889 spelt out the details of the Open Access Same-Time Information
System (OASIS).
1999 FERC Order 2000
Encourages the establishment of regional transmission organisations (RTOs).
Source: Energy Informer (July 2001), Reference [1].
that have inuenced the pace of deregulation in other states. For example, states such
as Oregon, Nevada and Arizona have put the decision to deregulate on hold. Some
Canadian provinces are taking a comparable path to deregulation.
11.2.2 UK electricity market trading
In England and Wales [2] before privatisation began, the electricity industry was a
classic, vertically integrated, government-owned monopoly, seen at that time as the
best way to provide a secure electricity supply. Consumers had no choice of supplier
and had to buy electricity fromtheir local regional electricity company (REC), so that
price competition was not possible.
The UKis one of the pioneer countries in developing a free market electricity trad-
ing system. On 27th March 2001, New Electricity Trading Arrangements (NETA)
for England and Wales were launched. The stated objectives of NETA are to benet
electricity consumers through lower electricity prices resulting from the efciency
of market economics. Promotion of competition in power generation and electric-
ity supply, in order to use market forces to drive consumer costs down, was, and
remains, a key objective of actions to liberalise and deregulate electricity markets
in the UK.
In England and Wales, the electricity market was progressively opened to com-
petition in generation and supply over a period of 10 years, with retail competition
for the smallest consumers completing full market liberalisation in 1998. A regu-
latory body, the Ofce of Gas and Electricity Markets (OFGEM), oversees market
operations, licensing, competition, and actively seeks to make changes to benet con-
sumers andbringtheir costs downwhile promotingcompetitionbetweenplayers inthe
electricity market. Sweeping away old thinking has led to electricity being regarded
Electricity trading 149
as a tradable commodity and revolutionised the business environment bringing new
market participants, new business opportunities and rapid change.
Initially market reform involved creating an Electricity Pool for England and
Wales with a single wholesale electricity price. Producers sold to the Pool and licensed
suppliers purchased electricity fromthe Pool. Pool participants were able to negotiate
bilateral contracts. However, the Pool performances did not allow the development
of full competition. The UK White Paper on Energy Policy and the Utilities Act
2000 incorporated proposals for trading arrangements similar to those in commodity
markets and energy markets elsewhere. NETA provided new structure and rates for
England and Wales electricity market. Under NETA there were major developments
in which electricity is bought and sold, with major competition in generation and
supply, with a wide range of new players competing in the liberalised energy market
as detailed in Figure 11.1.
NETA aims to develop a marketplace in which buyers and sellers can participate
through a variety of contracts and agreements within the framework set by NETA.
The transactions taking place within the NETA market are electricity pricequantity
transactions on a half-hourly basis.
Market players include generators producing electricity, suppliers who buy elec-
tricity to sell on to groups of consumers, traders and marketers who do not own
spot market and contracts
Brokers, OTC
contracts System operator NGC
transmission functions and
balancing operations
Supply and distribution companies
(former RECs)
energy suppliers
Third-party access
Utility distribution services (via former RECs)
Demand side
balancing and
ancillary bids
generators Inter-generator
Supply side
balancing and ancillary
real-time bids
Figure 11.1 NETA electricity market major contractual relationships (Reference
[2], OFGEM)
150 Economic evaluation of projects in the electricity supply industry
generating assets but have active roles in the market place, together with other players
who provide, for example, risk management, hedging and brokerage.
NETA is a new wholesale market, comprising trading between generators and
suppliers of electricity in England and Wales. Under NETA, bulk electricity is traded
forward through bilateral contracts and on one or more power exchanges. NETA also
provides central balancing mechanisms, which do two things: they help the National
Grid Company (NGC) to ensure that demand meets supply, second by second; and
they sort out who owes what to whom for any surpluses or shortfalls. The majority
of trading (98 per cent in the rst year) takes place in the forward contracts markets.
A very small percentage of electricity traded (2 per cent in the rst year) is subject to
the balancing arrangements.
It is hoped that most of the trading will be through bilateral contracts forwards
and future, which spot market trading utilised to adjust contractual positions. The
nature of the ESI does not allow spot pricing so that forward arrangements of the
nancial transactions are necessary.
Under NETAthe market provided through power exchanges replaces the previous
Pool arrangement, allowing market players to trade electricity up to one day ahead of
the requirement for physical delivery. The National Grid Company (NGC) operates
as a system operator for England and Wales, managing the HV transmission system
and also providing all the technical and operational services normally demanded by
the system to ensure its integrity including load forecasting, ensuring system security
and stability, frequency control, and reactive power control. NGC acts on both a
physical and a nancial level through the balancing mechanism, selecting bids and
offers for incremental or decremental supply of electricity in order to achieve physical
balance between generation and demand.
It is not intended here to go into the way the nancial and settlement activities
are undertaken in the England and Wales electricity market trading since these are
explained in detail in the literature [2].
11.2.3 The Nordic market
This involves Norway, Sweden, Finland and Denmark. The deregulation of the elec-
tricity market in these countries is complete with customers free to choose their
supplies. Trade of electricity (mainly generated by hydro-power) between the four
countries is extensive. In this market, generation and retail sales are competitive while
transmission and distribution are regulated. Third-party access to the transmission
network is regulated; therefore there are equal access rights to all users. The Nordic
network experience provides an excellent experience to European Electricity market
development. The Nordic electricity market general relationships are in Figure 11.2.
11.2.4 The California market
The pioneer California market provided the most severe challenge to competitive
electricity market philosophy. Restructuring of the ESI of California took place in
1996, with the aim of bringing the benets of competition to consumers. Prior to this
Electricity trading 151
TSO and
Wind Nuclear Thermo Nuclear Hydro
Transmission system
Nord pool
Third-party access
Marketers, brokers
and traders
Utility distribution
and supply companies
TSO and
TSO and
TSO and
Norway Sweden Finland
Figure 11.2 The Nordic market major contractual relationship [2]
regional utility companies investor-owned utilities (IOUs) provided monopoly
supply and services. These former utilities now each provide a regulated distribution
service in their areas, allowing direct access to third-party energy-service suppliers;
consumers now have a choice of electricity supplier.
When the new California electricity market structure took effect, the utilities had
the prices for their consumers frozen at 10 per cent below the level at vesting in
the expectation that costs and prices would fall. It was anticipated that consumer
electricity prices set at this level would allow the utilities to recover the cost of
investments that had been made before market liberalisation stranded costs. As events
unfolded, this proved to be entirely unfounded and resulted in the utilities business
becoming non-viable.
The crisis in the California electricity markets resulted from a combination of
factors [2].
Exceptionally high summer temperatures signicantly increasing electricity peak
A lack of generating capacity in California and the West of America in relation to
the strong growth of electrical demand following economic growth in California.
Ashortage of water resulting in relatively limited hydro-power import availability
from the North West of America.
An increase in gas prices for power generation compared with previous years.
Exercise of market power by generators and other market players.
Environmental restraints on the construction of new generating plant and
operation of existing plant.
152 Economic evaluation of projects in the electricity supply industry
Weakness and aws in the design of the electricity market including limitations
on forward contracting, xed consumer prices, but variable wholesale electricity
Insufcient importance being given to power engineering expertise in design
of market structures.
Shortage of installed capacity or plant availability due to outages, maintenance, or
generator market power, seems to have been a key driver for the California difculties.
Structural weaknesses in the design of the California market include restraints on
consumer prices but free competition in wholesale electricity prices and constraints
on utilities to buy through a power exchange. These factors were major contributors
to the problems of the California electricity market. In order to ensure proper and
reliable market trading it is imperative to ensure a technically viable and reliable
system. Electricity markets demand technological expertise in power engineering
plus a nancial and business expertise that allows market trading.
What California tried was not really deregulation. What failed were price controls
on retail electric rates, and an overly restricted, supposedly deregulated wholesale
market a mix that was denitely asking for trouble. Californias experience has
been a bit of a horror story, and truly is not a valid case against deregulation. It is,
instead, a case study of how not to deregulate.
11.2.5 Electricity markets across Europe and elsewhere
The European Commission Single Market Directive for Electricity came into effect
in February 1999. The Directive obliges EU Member States gradually to open
their power sectors to competition; to vertically unbundle the sector; and to ensure
nondiscriminatory access to the transmission network.
Energy markets across Europe are expected to be fully liberalised, privatised, and
integrated across borders by 2010. European companies and households will bene-
t from lower prices, better services, and free choice between alternative providers.
European utilities will be highly competitive as a result of cost cutting and con-
solidation. The EU Single Market for energy is expected to be the largest in the
world, comprising not only the current 15 Member States, but also up to 13 accession
countries, with a total of more than 400 million consumers.
Germany leads the European countries in progress towards deregulation and is the
regions largest electricity market by consumption. It is strategically important as a
base for further European expansion, with physical interconnection to many more
European markets than the UK. The country has two regulated exchanges, which have
merged into one entity. However, there is little liquidity on this market and brokers
have been more successful in trading, most notably through electronic trading in the
form of Alternative Trading Systems (ATS).
Australia and New Zealand were among the rst deregulated countries, and have
almost completed their transition and are rening and adjusting the implementation
of the new market rules. Singapore and Malaysia were expected to experience a full
opening of their markets in the third quarter of 2002, whereas Japan is only now
Electricity trading 153
seeing a partial opening to competition in the construction of merchant power plants
and the electricity supply to large customers.
North America pioneered reforms in the 1980s, but owing to its federal structure
has not yet completed the process in all states. Except for the UK and the Nordic
countries, Europe has embraced reforms relatively late but vigorously, and is now
arguably the fastest reforming continent. Latin America, the rst developing region
to liberalise and privatise its energy sector, has largely completed the reform agenda.
Many countries in Asia that introduced IPPs without liberalisation suffered from the
consequences during the recent nancial crisis, and are nowmoving towards the Latin
American model. Together with Sub-Saharan Africa, the countries of the southern
Mediterranean are lagging considerably behind international reform trends [3].
At the beginning of 2002, there were approximately ten regulated electricity
exchanges in Europe, with eight ATS trading electricity in the region and at least
three more regulated exchanges and a further three ATSs close to introduction. With
wholesale markets at very different stages of development ineachcountryit is onlyfair
to describe the European picture as fragmented and largely immature, characterised
by the number of regions and exchanges; the lack of appropriate instruments; issues
around transparency and liquidity; and restricted inter-regional trading.
But the immaturity of electricity trading in most countries has not prevented the
creation of new trading exchanges. Indeed, in some new territories, particularly those
in which legislation supports competition, an under-developed market offers greater
potential gains once maturity and liquidity is reached.
The UK is a good example of this. At the beginning of 2002 there were four
exchanges competing for market share in a region where electricity consumption is
below the European average. The ght is on between these exchanges, partly because
the region presents a considerable reward, but also because it will act as a good
proving ground, offering a chance for exchanges to cut their teeth before moving on
to markets that are less developed.
Generators, wholesalers and retailers access exchanges through the trading activ-
ities of internal business units or by outsourcing to trading companies. As electricity
prices are extremely volatile, successful trading activity depends on a good risk man-
agement policy and implementation. The number and nature of players will evolve, as
the electricity market continues to open and the liquidity of exchanges increases. The
increase in electronic trading of all forms has resulted in the need for companies to
reassess the way in which they trade and the way in which electronic trading impacts
on their risk policy.
11.3 Electricity traders
Because of price volatility in the bulk supply markets the importance of electricity
traders has increased during recent years [1]. Correspondingly risk management and
hedging against such volatility is one of the critical services offered by electricity
traders. This is likely to be extended soon from the bulk supply market to the retail
competitive markets. Electricity traders have access to valuable information (prices,
154 Economic evaluation of projects in the electricity supply industry
options, etc.), which will also assist their clients in reducing costs, increasing prots
and improving performance. They can also broker and undertake transaction manage-
ment and assist in providing liquidity by helping their customer to change position
The electricity-related services provided by power traders include physical
delivery of power and/or a nancial obligation or promise to do so. Such services
extend beyond electricity into other energy-related services like natural gas. The
delivery may be rmor non-rm, short or long term, one time or stretching over time.
Prices may be rm or indexed to other commodities or derived from combination of
underlying commodity prices, hence derived markets. Many operators in the elec-
tricity business will not be able to function successfully in the liberalised competitive
electricity market without the help of an electricity marketer.
Electricity marketing has to investigate customer needs, decide on the prices to
offer and the considerable risks and how to manage them through mitigation and
hedging strategies. Small, uncorrelated risks may simply be managed through risk
pooling. Aggregating a large number of small risks, which are not correlated, is the
easiest way to manage risk (see Chapter 14).
As from the beginning of the 21st century, electricity trading is growing at a
phenomenal rate. In the US the annual volume of wholesale electricity commodity
trading was anticipated to reach $2.5 trillion by the year 2003 and online transactions
to reach $4 trillion by 2005 (see Figure 11.3). Such amounts will make electricity the
single largest traded commodity in the US. By 2003 the $2.5 trillion was expected to
be about 10 times the retail value of electricity trade in the US. This is made possible
by the developments in nancial trading instruments such as futures, forwards, swaps,
and options that allow the same electrons to be bought and sold several times before
they are actually generated and consumed. The volume of trade is typically many
2001 2002 2003 2004 2005
Physical natural gas
Physical electricity
Physical crude oil
Financial natural gas
Financial electricity
Financial crude oil
Figure 11.3 Online energy trading projections (Forrester Research and
Reference [1])
Electricity trading 155
times the physical number of kWh generated or consumed because many times an
electricity trader will be buying from or selling to another trader. Correspondingly
the same kWh is usually bought and sold a number of times until it is nally delivered
and consumed.
The services an electricity trader can offer are discussed in Section 11.3.1. The
most important is the quantication, management and hedging of risk.
11.3.1 Case study: sample of services offered by
power marketers (traders)
The services most commonly offered are categorised as follows [1].
Facilities management
Many utilities and customers can benet from improvements in the utilisation, main-
tenance and operation of their existing assets, plants, infrastructure and personnel.
This is particularly true for some of the smaller utilities that may not have adequate
in-house or internal resources for such services, and outsource them to others. These
services are usually provided in addition to more traditional power-marketing func-
tions such as selling the excess output of the plant (e.g. what is not needed to serve the
utilitys native load) to the highest bidders outside the utilitys immediate service area.
The savings resulting from the improved operations and maintenance (O&M)
practices are usually shared among the two parties under pre-arranged terms. The
power marketers willingness to manage certain critical O&M functions, assume
risks, and arrange nancing makes such schemes highly attractive to many clients
who do not have the internal resources or expertise to engage in such functions.
Since no up-front investment may be needed, and no risk is borne if there are no
improvements in performance of the plants, there is little risk to engage in such deals
with power marketers.
Risk management
Offering a variety of services to provide price stability and risk hedging is among
the most sought-after services provided by power marketers. Since many customers
and smaller utilities are not familiar with, and do not have the necessary skills and
capabilities to manage, the risks internally, they rely on power marketers for such
Total energy services, solutions, maintenance, etc.
By combining many types of input fuels (e.g. natural gas, coal, oil) and end-use energy
and/or services (e.g. electricity, natural gas, steam, hot water, and others) it may be
possible to reduce a customers overall energy costs while at the same time providing
an improved level of service. For example, by switching from natural gas to coal on
the fuel side, and/or by switching from electricity to natural gas on the end-use side,
a customer can take advantage of lower price opportunities.
156 Economic evaluation of projects in the electricity supply industry
Tolling services
The power marketers ability and willingness to buy raw energy at low prices in
one location or time and to deliver a portfolio of desirable energy services and
customised products at the another location or time is highly attractive. Although cus-
tomers can, in principle, perform these functions on their own, many do not have the
market reach or the risk-management capabilities of the power marketers. Moreover,
power marketers, by virtue of having many offsetting tolling transactions, can balance
the risks of market price uctuations through pooling and other arrangements, thus
reducing the risks to the individual customers.
Structured/customised products
Structured or customised products are increasingly emerging to meet the specic
needs of sophisticatedcustomers. Another reasonfor their increasedpopularityamong
power marketers is that customers are willing to pay signicant premium for these
types of services. Offering a package of customised goods and nancial services that
meet specic customer needs, their nancial resources, and risk tolerance, however,
tends to be time- and resource-intensive, hence the higher premiums.
These types of services cannot, by their nature, be standardised. They require
extensive effort to negotiate and complete. But the results could be worth the extra
11.4 Future strategies and growth
Although the introduction of competition in electricity markets is high up the Euro-
pean agenda, there is still some way to go before market integration is complete
[4]. As a result, exchanges need to adopt country-by-country strategies, recognis-
ing the deregulation agenda and conforming to the competitive environment of each
individual country. In essence, exchanges need to adopt a portfolio approach that
encompasses corporate strategy, the market environment of each country and the
competitive landscape. The legislative environment and regulatory regime of each
country need to be considered, as well as the differences in the countrys market
potential, market participants and competitors. Potential partnerships and alliances
can be vital and these opportunities should not be overlooked.
The surge inthe development andgrowthof electricityexchanges aroundthe world
has largely been driven by the triumvirate of market forces: legislation, competition
and technology. This trend is likely to continue in the short term as legislation in
Europe and North America increases the number of new markets opening. In the
medium and long term, however, customer demand and increasing competition will
be the driving forces.
The worlds electricity markets are fragmented and immature; and the European
electricity industry, for all its successes, is typical of the global situation. While there
are already many exchanges, both of the regulated exchange and the ATS varieties,
there will be continued growth in the number of exchanges in the short term.
Electricity trading 157
Much of this growth in numbers could be reversed in ve years time, as a strong
period of consolidation results in the birth of mega-exchanges. During this time, there
will be unprecedented access to new markets through deregulation, better integration
of the fragmented markets in Europe and North America, and truly mature markets
will develop in these regions, both in electricity and gas. This represents signicant
change and unprecedented opportunity for energy traders and exchanges alike. Being
successful requires the right strategy, the right partnerships and the ability to execute
those plans globally and on a portfolio basis.
11.5 References
1 SIOSHANSI, F. P.: Electricity trading, Energy Policy, 2002, 30, pp. 449459
2 STEPHENSON, P., and PAUN, M.: Electricity market trading, Power Engi-
neering Journal, 2002, pp. 277288
3 MULLER-JENTSCH, D.: The Development of Electricity Markets in the
Euro Mediterranean Area, The World Bank Technical, Paper No. 491, 2001,
Washington D.C
4 COOPER, C.: Survival of the ttest, Electricity International, February 2002,
14, pp. 1420
Chapter 12
Evolvement of the electricity sector utility
for the future
12.1 Introduction
During the last decade of the 20th century the electricity supply industry underwent
major evolvement and restructuring [1]. Until very recently most network industries
(mainly the electricity supply industry, but also gas, water and telecommunications)
were considered to be natural monopolies. Their size, networks, capital-intensive
nature and their sensitive services to the public meant, in most cases, exclusive
government ownership and control. Recently, however, technological progress,
particularly in information technologies and telecommunications as well as develop-
ment of regulatory instruments has enabled the introduction of a market mechanism
into these traditional monopolies. Developments vary from one country, or region, to
another but a general pattern of four phases developed.
12.1.1 Phase I: early 20th century private sector
investment and monopolistic market behaviour
The infrastructure investments in the late 19th and early 20th century were largely
undertaken by private companies. Private rms developed and commercialised the
technologies for the production and delivery of electricity and natural gas. Local
monopolies, and national and international oligopolies that used their market power to
extract economic rents fromcaptive customers, dominated the newindustry. Delivery
to users was generally conned to urban communities, with limited development of
distribution grids in rural areas. There was little competition in the sector during this
period of rapid innovation and industry expansion.
12.1.2 Phase II: mid-20th century public sector
intervention and inefciency
Around the time of World War II, a trend towards the nationalisation of energy assets
or at least strong government regulation of privately owned monopolies became the
160 Economic evaluation of projects in the electricity supply industry
norm, in an attempt to limit abuses of market power. In many countries, govern-
ments also played an important role in rural electrication, since returns were too
low to attract private capital. Elsewhere, state ownership of the electricity industry
became the rule. Over time, however, public ownership and the absence of com-
petition increasingly undermined effective management, innovation and operational
efciency. Governments used the power sector, like other state-owned industries,
articially to create employment and as an instrument to deliver hidden subsidies to
parts of the economy.
12.1.3 Phase III: late-20th century unbundling, competition,
regulation and privatisation
The economic costs of public ownership and monopolistic market structures became
more and more apparent. In the 1970s, the United States began to experiment
with power sector reform. By the 1980s, policy makers in Europe, the Americas
and elsewhere realised that electricity, natural gas and telecommunications were no
longer natural monopolies. Thanks to advances in technology, economic theory, and
increasingly sophisticated regulatory instruments, it became feasible to introduce
competition with the same effect as in other industries. Substantial improvements in
operational and investment efciency, the reduction of costs to end-users, an improve-
ment of services, and a higher rate of innovation thus became possible. During
the 1990s, electricity and natural-gas sectors have been transformed through the
overhaul of regulatory frameworks, the introduction of competition, and increasing
private participation. These policy reforms have been implemented in developed and
developing countries alike.
12.1.4 Phase IV: recent developments industry convergence
and globalisation
The fourth phase, which is now overlapping with the third, is characterised by
convergence in the electricity, natural gas, and more generally the utility sector.
Multi-utilities are being formed to offer comprehensive service packages to clients
and reap the associated economies of scale. As liberalisation and privatisation are
taking hold, the industry is rapidly globalising through international mergers and
acquisitions, cross-border trade, and the creation of regional power pools. Another
facet of the fourth phase is the emergence of a newservice sector in the power indus-
try, quite distinct from physical distribution, classied now as the wires business,
involving electricity markets, and trade.
12.2 Reorganising the ESI
The ESI worldwide is being restructured, liberalised, privatised, corporatised and
deregulated [2]. The meaning and differences of these terms [3] are explained here.
Restructuring. A broad term, referring to attempts to reorganise the roles of market
players and/or redene the rules of the game, but not necessarilyderegulate the market.
Evolvement of the electricity sector utility for the future 161
California, for example, restructured its market, deregulated its wholesale market by
lifting nearly all restrictions, but kept its retail market fully regulated. Many problems
Liberalisation. This is synonymous with restructuring. It refers to attempts to intro-
duce competition in some or all segments of the market, and remove barriers to trade.
The European Union, for example, refers to their efforts under this umbrella term.
Note that liberalisation is essentially a misnomer. No electricity market has been
(or, in fact, can be) fully deregulated. Experience suggests that even well functioning
competitive markets need a regulator, or as a minimum, a market monitoring and
anti-cartel authority. Germany is the only major country attempting to do without
a regulator. Even in this case, there is an anti-cartel ofce, monitoring the behaviour
of the market participants.
Privatisation. Generally refers to selling government-owned assets to the private sec-
tor, as was done in Victoria, Australia, and in England and Wales. It must be noted
that one can liberalise the market without necessarily privatising the industry, as has
successfully been done in Norway. The experience in New South Wales, in Australia,
has been a mixed success.
Corporatisation. Generally refers to attempts to make state-owned enterprises (SOEs)
look, act and behave as if they were for-prot, private entities. In this case, the SOE is
made into a corporation with the government treasury as the single shareholder. For
example, former SOEs in New South Wales, Australia, have been corporatised. They
vigorously compete with one another, while all belong to the same, single shareholder,
namely the Government of NSW. The Islamic Republic of Iran has been considering
such a move for generators.
Liberalising (restructuring) splits off two lines of the power business that until
now have been controlled by the monopoly utilities the generation of electricity,
and the billing and metering of it and allows new players to compete in providing
those services. Further, it allows these competitors to set their own prices, rather than
negotiating with state regulators on a xed rate.
Only a handful of companies are competing to provide billing and metering ser-
vices. But many are looking to be the biggest and the best at owning and operating
power plants. Those players are usuallyunregulatedsubsidiaries of holdingcompanies
for traditional utilities, or independent companies that own only power plants.
Eventually, these companies will sell most, if not all, of the electricity into the
wholesale market, where utilities and power marketers that distribute to retailers will
purchase the power. The wholesale market is growing, and is considered crucial
to liberalisation because buyers will pay prices based on supply and demand. That
means, liberalisation proponents argue, that power-plant owners will attempt to oper-
ate the most efcient plants possible, and then sell electricity at the cheapest rate to
marketers. They also argue that, currently, utilities have little incentive to operate
efciently because they get a guaranteed rate of return from regulators based on how
much the plant costs to build and maintain. This is true but only to a certain extent.
162 Economic evaluation of projects in the electricity supply industry
As we will see there is a need for an alert regulator to avoid market volatility and
ensure fair play of the markets. Disaggregation of the value chain and beneting
of new technologies, particularly in information, helped creating electricity trading
and markets. Liberalisation and technology advances are driving industry transfor-
mation and a newvision of the digital utility, which is able to gain business advantage
focusing on a few segments of the energy production and delivery value chain
such as generation, transmission, customer care, and billing or new areas like
energy trading and risk management; and
achieving efciencies through economies of scale gained from concentration
on building best-in-class, core, mission-critical, business systems and partner-
ing, outsourcing, or procuring the other less critical or more contextual business
services required for business operations.
While liberalisation may be viewed as a driving force, the power of software and
the emerging capabilities for increased collaboration and integration through open
Internet-based standards are enabling and simplifying this transformation. A truly
excellent software platform and applications environment provides the ability to:
visualise, by delivering the right information in real-time where needed within
a personalised portal view on any device including mobile wireless devices;
optimise, by taking this information and combining it with other information
seamlessly to get a complete picture, nding individuals with expertise that one
can collaborate with, and using the information to do analysis; and
automate, by executing processes and transacting business, which may require
orchestration among many systems and processes and interoperability with many
different heterogeneous systems.
12.2.1 The opportunities presented by liberalisation
Figure 12.1 outlines ve possible (but not exhaustive) models for the future organisa-
tion of the electricity industry [2]. The ve models range from the most conservative,
which enables all players in the industry to intervene (model 1), to the solution
that rules out all intermediate stages (model 5). A distinction is made between net-
work distribution (physical transportation of electricity) and marketing distribution
(supply). Third-party access (TPA) enables all players in the industry to be potential
suppliers, whether they are producers, transporters, network distributors or marketers
(physical traders). Marketers have a unique status, as they are the only participants to
focus on supply, since they buy electricity in bulk and sell it to eligible clients.
Inmodel 1, eligible buyers are suppliedbymarketers, whothemselves are supplied
by (network) distributors. The distributor buys the electricity from the transporter,
who is the only player to have direct contact with the producer.
In model 5, eligible buyers skip all the intermediate stages between themselves
and the producer, and negotiate their supply directly with the producer. This can
also happen in reverse order, i.e. the producer may directly approach an eligible
Evolvement of the electricity sector utility for the future 163
Model 5 Model 4 Model 3 Model 2 Model 1
Eligible Customer Eligible Customer Eligible Customer Eligible Customer Eligible Customer
Generators Generators
Generators Generators
Distributor Distributor Distributor
Figure 12.1 Possible models for the organisation of the electricity industry
customer. Under this model, the transporters and distributors only handle the physical
transportation of electricity, as stipulated in the directive.
There are several intermediate stages between these two extremes three of which
are models 2, 3, and 4. Model 2 represents the situation that dominated the European
electricity industry for a long time, with two slight differences: rst that the producer
was often also the transporter, and even the distributor; and, second, that some major
consumers were supplied directly from the transporters network.
With liberalisation, the three main players (producers, transmission and distribu-
tors, marketers) are likely to have different fortunes.
(1) Enhanced opportunities for producers. Producers have the advantage of con-
trolling the resource in question. Liberalisation of the market will enable them
to sell directly to consumers and to maximise their prots, as they will only pay
the transmission company and the distributor the cost of using the networks.
Alongside these opportunities in terms of direct contact with the customer,
electricity producers are beneting from increasing synergies between natural
gas and electricity at the production level.
(2) New challenge and reduced role for transmission companies and distributors.
At rst sight, transporters and distributors are the main losers from liberalisa-
tion. As they are forced to open their networks to competitors, they will lose
control of a key link in the chain, which afforded them control over supply.
The challenge facing these players is to combine their traditional expertise in
network management (and production in certain cases) with expertise in supply.
This is the condition that will enable transporters and distributors to retain their
position as key players in the market, capable of handling their own electricity
production as well as that bought from other producers on increasingly compet-
itive markets. In this respect, the opening of the markets constitutes a sizable
opportunity. These opportunities are local as well as global.
164 Economic evaluation of projects in the electricity supply industry
(3) Traders as the link between producers and consumers. The main advantage that
these traders have regarding nal consumers is their understanding of the market
(i.e. their knowledge of the cheapest sources of supply) and their capacity to buy
large volumes of electricity, which provides them with access to competitive
supply tariffs. Similarly, producers, who do not have the expertise needed to
ensure sufcient penetration of consumer markets, will prefer to work with
external traders who are able to offer such market penetration.
12.3 Barriers in liberalised markets
Monopolies exist because other rms nd it unprotable or impossible to enter the
market. Correspondingly, monopolies exist because of barriers [4]. However, in order
for perfectly competitive prices to develop, fundamental assumptions of competitive
markets must be met. One of these assumptions the ease in which rms are able to
enter markets plays an important role in the development of competitive markets.
Market entry assures (1) that long-run prots are eliminated by the new entrants
as prices are driven to be equal to marginal cost, and (2) that rms will produce at
the low points of their long-run average cost curves. Even in oligopolistic markets,
long-run prots and prices exceeding marginal cost can be eliminated if entry is
The recent California experience has highlighted the full extent of barriers facing
new generation, and the cost to society when entry is constrained. However, until
the barriers to entry are relaxed, prices will not be set at marginal cost. Because
entrepreneurial merchant generation is unable to quickly enter the market to capture
excess rents, existing generation is able to charge prices exceeding marginal cost.
There are several reasons why entry is constrained, including site develop-
ment and permitting delays, turbine availability and construction lead-time. Both
advanced and conventional combined-cycle technologies require three years con-
struction lead-time, while coal and nuclear plants require four years and more. Once
the facility is built, transmission rights and fuel availability constraints can limit
market participation. Finally, scheduled maintenance and physically operating con-
straints can limit real-time market participation. It is apparent that physical generation
by itself will not provide real-time market entry and exit required to assure marginal
cost pricing.
12.4 Electricity and the new digital economy
The 20th century was characterised by the industrial analogue economy. The economy
of the 21st century is the networked digital economy [5], which only runs on electricity
characterised by a real-time ow of information. Electricity-based innovation lies at
the heart of economic growth.
Digitisation of the global economy has proceeded in three phases. First came com-
puters, which revolutionised information processing and fundamentally transformed
Evolvement of the electricity sector utility for the future 165
the way most businesses operate. Next, as the cost of microprocessors plunged, indi-
vidual silicon chips began appearing in many applications from industrial process
equipment and medical instrumentation to ofce machines and home appliances.
Now, phase three involves linking these computers and microprocessors together into
networks. There are, at the beginning of the 21st century, more than a million Web
sites available on the Internet, potentially available to more that 200 million computers
around the world. Eventually, many stand-alone microprocessors will also be linked
to networks, supplying critical information on equipment operations and facilitating
even more profound changes in daily life.
This proliferation raises two challenges: quantity and quality. Quantity has to be
met not only in building newpower stations and generating plants but also in enlarging
and strengthening the transmission network, building new interconnections, as well
as enhancing the distribution system. Quality was dealt with in Chapter 11.
In 2001 the information technology (IT) itself accounted for an estimated
13 per cent of the electrical energy consumed in the US, a proportion that may grow
to as much as 50 per cent by 2020, as shown in Figure 12.2.
The new digital-quality power needs are as explained above in terms of quantity
as well as quality. Such needs can be fostered by:
leveraging the advantages of distributed resources,
dening and facilitating value-added electricity services,
providing new d.c. electricity supply technologies,
developing and employing advanced power conditioning, power quality devices,
and power electronics, and
establishing new service quality standards for electricity and related products.
Most of these needs have already been discussed in the book.

1980 2000 2020
13% Digital
Analogue power
Figure 12.2 Information technology accounts for an estimated 13 per cent of the
electrical energy consumed in the United States, a proportion that
is growing rapidly
166 Economic evaluation of projects in the electricity supply industry
12.5 The utility of the future
Liberalisation provides for third-party access to the electricity grid and the estab-
lishment of independent grid operations [57]. In doing so, it will also provide for
increased retail competition, starting with the largest electricity customers. Another
feature is the unbundling of the vertically integrated value chain, creating different
roles for current utility industry entities and allowing new players to enter the market.
The utility companies of the past ran the entire process, from generation to
retail settlement. The new unbundled value chain breaks out the functions into four
basic entity types; different factors dene success within each of these four distinct
Generators will need to optimise generation outputs according to market demand,
comply with environmental rules, prepare for new investments, and decrease
maintenance and operation costs.
Energy network owners and operators will concentrate on new ways to secure
physical delivery, decrease maintenance and operation costs, plan new invest-
ments, and ensure compliance with regulatory authorities.
Energy traders, brokers, and exchanges should focus efforts on creating trad-
ing vehicles and market liquidity, managing risk exposure, lowering transaction
costs and developing new wholesale offers that make the best use of connectivity
Energy service providers and retailers will establish ways to reduce energy-
sourcing costs, manage client portfolios and risk proles, bundle and market
new services, and launch innovative offerings to large clients.
Liberalisation forces a disaggregated business model for each separate element of the
value chain, even if the specic models differ from country to country and region to
region. This disaggregation promotes the inclusion of new participants with a new
combination of roles into the market, participants (such as asset managers, whole-
salers, traders, and transmission system operators) who did not exist a few years ago
in the utilities landscape.
Many of the structural changes that must take place during the transition will be
driven by newtechnologies, such as electronic exchanges and online trading. Todays
focus is on external communication needs to interconnect all of the participants,
including suppliers, customers, and partners, in the value chain.
The large utility of the future must be able to thrive in a competitive, global market
for energy [7]:
it is multinational,
it can carry its expertise over into emerging parallel businesses,
it has the exibility and willingness to unbundle,
it adapts readily to new structures and concepts,
it goes beyond its traditional geographic borders to grow, and
it is an expert manager of risk.
Evolvement of the electricity sector utility for the future 167
The utility has to learn to operate in different cultures, regulatory environments
and markets. The big challenge is in the huge transitions that occur when the industry
is transformed by privatisation, consolidation, liberalisation, and the introduction of
real free-market competition, not to mention the convergence of energy, capital, and
The utility of the future will have the exibility and willingness to unbundle
whenever doingsocanaddvalue andcompetitive advantage as well as improve service
to the customer. Risk management will be more important than ever in tomorrows
more deregulated energy markets because it protects businesses, municipalities and
other entities affected by change in the energy market, the weather, or other factors.
The utility of the future will manage commodity price risk with options, swaps and
other derivatives. Increasingly, it will be bundling energy, capital and actuarial risk
products to manage a broader array of client risks. The benet is that it will be
able to manage risk for itself and its clients, commercialising or productising risk
management services. The utility of the future will be an expert manager of risk and
help customers determine and achieve an acceptable risk level.
12.6 The virtual utility of the future
Gradually more distributed generation is going to evolve, and most of it will be small
units connected to the grid. Such small and decentralised electric energy sources can
be operated over the Internet as one large generating plant, a virtual utility [8]. Such
development is being enhanced by environmental considerations that are encouraging
small renewable energy sources, the fastest growing of which is wind power and small
hydro, microturbines and in the future, fuel cells. Such systems may be interconnected
by d.c. transmission systems through low-cost cable network.
This is accompanied by a trend towards neater and aesthetically more appealing
arrangements of the network; underground cables are growing while overhead lines
are shrinking in size. Cable technologies are allowing for economical and easy-to-
install systems. Substations are becoming more compact and easier to conceal. Major
advances and cost reduction are also taking place in HVDC light technologies.
These multi-sources will need extended and sophisticated control of all the com-
ponents and the power ow. The decentralised electric power generation and related
revenue ows will most likely be handled by the Internet for direct control, and also
for maintenance of the grid as well as for nancial and administrative transactions.
12.7 DSM programmes in deregulated markets
In regulated markets, the cost and responsibility of demand side management (DSM)
programmes were built into the rate-base or funded through green energy surcharges.
In deregulated markets, where DSM programmes or renewable energy investment
must be recoverable through market-based pricing, these programmes have been
considered uneconomic and thus neglected [4].
168 Economic evaluation of projects in the electricity supply industry
Theoretically, real-time load management is analogous to physical ancillary gen-
eration markets. Rather than dispatching and curtailing generation, real-time load
management curtails and dispatches load. However, owing to the high cost of mon-
itoring and telemetry equipment and current limitations in market design, practical
real-time load management is only available to large industrial consumers.
However, residential consumers can also participate in load-curtailment markets.
Residential customers can be encouraged to shift demand from peak to off-peak
hours via a multi-tier tariff. For example, a simple two-tier system that prices peak
power consumption differently from off-peak would provide incentives to shift non-
essential activity to off-peak hours. Although limited, the opportunities for residential
consumers provide a signicant potential source of peak-load reduction. However,
the current system of load proling is fundamentally inconsistent with real-time load
measurement and pricing.
Demand responsiveness markets will be most effective when shedding peak load.
Experience has shownthat a small demandreductioncouldeffectivelybringwholesale
prices way down. In many service territories, peak demand for the system, which may
represent only 100 h or so per year, creates the need for 1025 per cent greater system
capacity. For peak-load shedding markets to develop, peak-load price signals must
be passed to end-use customers. As price signals become apparent, more end-users
will nd the exibility and desire to sell back megawatts into the grid.
The most successful programmes avoid much of the downside price risk through
voluntary participation. Instead of threatening users with the possibility of extreme
energy costs, voluntary programmes pass the price signals to the consumer and,
therefore, the incentive tocurtail. However, if the consumer chooses not torespondand
continues current consumption, they pay the conventional stable rate for electricity.
Under voluntary load curtailment, the energy user pays a standard rate that is designed
to average out the highs and lows but, during a price spike event, the user can sell
back the curtailed energy to the electricity supplier.
Ideally, the electricity supplies would be indifferent to either paying the gener-
ating company the spot market price for wholesale energy or paying the large load
reducing negawatt participant for load curtailment. Under this scenario, the end-use
customer receives the full benet of equivalent spot market prices for participation
in the negawatt market. The benet to the supplier is less apparent. If the load cur-
tailment generates enough savings, the market would face a less-expensive marginal
unit setting market price. In this case the supplier would receive a higher return on
power sold to xed tariff customers.
Load responsive negawatt markets can provide system capacity through either
reducing consumption or switching to backup-generation. For the purpose of calcu-
lating the cost to shed system load, the two options are equivalent. Both switching
to backup-generation and shedding load represent opportunity cost. However, the
advantage of focusing on the cost of backup-generation is that it effectively sets an
upward bound on cost. The annualised cost of backup-generation effectively caps
the power market annualised price. At the point where system cost exceeds the cost
of new generation, negawatt market participants would be better off installing new
backup-generation than purchasing from the power market. Negawatt markets would
Evolvement of the electricity sector utility for the future 169
compete directly with the generating company, creating a demand response cap to
market price and volatility.
Although negawatt market participation can be either through reducing consump-
tion or switching to backup-generation, for the purpose of market pricing, we consider
all participation as if through backup-generation.
Participants in an energy reduction programme receive a corresponding premium
payment and an energy credit for curtailed energy. The premium payment is based
on the strike price, the option load contracted and the operational plan selected.
A call option in this case gives the supplier the right to purchase energy from the
end-use customer at the agreed upon strike price. The call option is exercised when
the supplier marginal cost of electric energy, including all variable cost associated
with delivering the energy, is projected to be equal to or greater than the strike price.
management curtails and dispatches load. Responsive load negawatt markets can be
developed to create real-time entry and exit fundamental to competitive priced electric
power markets. Negawatt markets would compete directly with generating compa-
nies, creating a demand response cap to market price and volatility. Generators would
compete with backup-generation, the cost of which sets the market cap.
Using a market-based method of pricing real-time load curtailment, based on real-
option valuation of participant opportunity costs, price incentives exist for negawatt
market development. The strike price is givenbya contractuallyagreeduponthreshold
price between the energy provider and energy consumer. From price volatility deter-
mined from historic price data or implied from forward markets, a premium value
is calculated for the right to curtail future load. Option premiums, prot sharing and
limit orders can provide nancial incentives for functioning demand responsiveness
12.8 The need for a regulator
It is thought that liberalisation will eliminate the need for a regulator [9]. It is also
thought that powerful price signals emanating from uctuations in supply and
demand are generally adequate to regulate competitive markets. There are cyclical
shortages, which result in higher prices, which encourage increased supplies and,
which bring prices back to normal levels. So self-correcting competition, obviates
the need for a regulator to monitor prices and signal when additional supplies are
needed and so on. Such arguments do not seem to apply adequately to electricity
An alert and all-powerful regulator appears to be needed particularly during the
critical early years of market reform because the market may not function properly
from the beginning. But even after the initial difculties in the system are worked
out, there appears to be a continuing role for the regulator to enforce the rules, and to
ensure competitive behaviour among market participants.
170 Economic evaluation of projects in the electricity supply industry
One of the key questions for policy makers and regulators is whether there are ade-
quate incentives for investment in generation, transmission, and distribution networks
in competitive electricity markets. This is an issue that a regulator has to monitor,
providing encouragement and incentives for the market to invest to cover for a gradual
increase in demand. However, encouraging adequate private investment in transmis-
sion is not easy. Costs are reasonably well known, but benets are difcult to measure
and harder to collect because they may accrue to third parties. An alert regulator will
have to monitor the network and ensure that there are rewards and incentives to invest
in transmission strengthening.
12.9 References
1 The Development of Electricity Markets in the Euro Mediterranean Area,
Daniel Muller Jentsch, The World Bank Technical Paper 491. The World Bank,
Washington, D.C., 2001
2 NYOUKE, E.: Deregulation and the Future of the Electricity Supply Industry.
World Power, 2000, pp. 3438
3 SIOSHANSI, F.: Sobering Realities of Liberalizing Electricity Markets, IAEE
Newsletter, Third Quarter 2002, pp. 2432
4 SKINNER, K.: Market Design and Pricing Incentives for the Development of
Regulated Real-Time Load Responsiveness Markets, IAEA Newsletter, First
Quarter 2002
5 LEWINER, C.: Utility of Future Business and Technology Trends, IEEE
Power Engineering Review, Dec 2001, pp. 79
6 GELLINGS, C., and SAMOYTI, M.: Electricity and the NewNational Economy,
Electric Infrastructure to Power a Digital Society, IEEE Power Engineering
Review, January 2002
7 GREEN, R.: Twenty First Century Utilities, IEEE Power Engineering Review,
Dec 2001, pp. 46
8 BAYEGAN, M.: A Vision of the Future Grid, IEEE Power Engineering Review,
Dec 21, 2001, pp. 1011
9 IEA.: Investment and Security of Supply in Electricity Markets, 2002
Chapter 13
Project analysis: evaluation of
risk and uncertainty
13.1 Introduction
From a practical point of view there is no project without risks. Risk taking is normal
to entrepreneurs, to lending and funding agencies and also in government develop-
ment plans. Such risks and their extent are reected in choosing the discount rate of
the project (see Chapter 4), where investors expect higher returns to compensate them
for risk taking. Because of the regulatory nature of the industry, the limited number of
players and the unique nature of electricity and its continuous rise in demand, the aver-
age project in the electricity supply industry is less risky than the average investment in
the stock exchange [1,2]. However, each project has its own risk; projects that involve
new technologies (renewable and clean-coal technologies), or projects with lengthy
lead times (nuclear and hydro-power) involve a lot of investment and have more than
the average level of risk. Some of the risks are related to engineering and technology;
however, market risks equally exist. For example, the demand may not turn out to
be as estimated, the tariff is lower than expected, project execution may take more
time and involve more cost than planned. Future fuel prices are one of the most risky
aspects in evaluating investments in the electricity supply industry projects. Variation
in fuel prices may surpass expectations, or supplies may turn out to be insecure and
more expensive alternatives have to be sought. For projects with lengthy lives, like
coal-ring and nuclear power stations, the problems of obsolescence (due to techno-
logical change) and environmental legislation exist; these may cause such projects
not to survive their full life or end up with heavy and expensive modications. Cost
overruns, which are caused by project delays, or inaccuracies in estimation do not
only signicantly change project costs but also substantially reduce net benets.
13.2 Project risks
Project evaluation involves assumptions about inputs with varying degrees of
uncertainty; in some cases these individual uncertainties can combine to produce
172 Economic evaluation of projects in the electricity supply industry
a total uncertainty of critical proportions [3]. The risks can come from three sources:
uncertainty in project planning and specications, uncertainty in the design coef-
cients (engineering and technology, economic and income prediction, etc.) and
uncertainty in exogenous project inputs (mainly fuel availability and prices). Sensi-
tivity and risk analysis affect the choice of the least-cost solution as well as the IRR
and correspondingly the decision to proceed with the project altogether.
Most of the nancial and project evaluation of Chapters 5 and 7 was on a determin-
istic basis, i.e. all inputs of costs and benets and corresponding cash ow forecasts
were assumed to be accurate. Risks were only incorporated in the discount rate and
in allowing for contingencies in project cost, and when net present values were cal-
culated. As already explained, in the real world things never work out that nicely.
Therefore it is prudent to account for such uncertainties by carrying out some project
risk analysis. Such analysis involves the following.
Evaluation and judgement about the behaviour of certain uncontrollable inputs of
the project. Calculating, instead of a single return, a whole set of possible returns
for the project based on the behaviour of the uncontrollable inputs.
Criteria for choosing the least-cost solution among the different alternatives
based on the likely set of returns for each. A less-risky project alternative with
modest returns may be preferred to a more-risky alternative with probably higher
Apart from giving a more realistic and accurate assessment of the likely outcome of
the project, a risk and uncertainty analysis has many other advantages. It enables
more accurate analysis and evaluation of project inputs and outcomes by many
experts and with more factual evidence. This will also lead to an insight into
restructuring or redesigning the project in light of this evaluation and analysis. It
also enables focusing on those uncertain inputs that affect the likely outcome so
as to mitigate or reduce their uncertainty in a number of ways. Project analysis
is greatly assisted by modern computers and statistical analysis packages, which
allow undertaking of such evaluation in a short time and at a limited cost. How-
ever, it needs a lot of insight and accurate understanding of the project structure and
Uncertainties faced by power utilities are both internal factors, which can be
controlled even to a certain extent by the utility, and external factors, which are
outside the control of the utility (see Table 13.1). Internal factors can be managed by
better handling of the projects design, execution and operation; outside factors have
to be incorporated into the planning process in order to reduce their uncertainty. The
experience of planners and designers greatly assists in dening uncertainties and their
handling. Post-evaluation of projects to compare the planning assumptions (costs,
execution period, demand prediction, etc.) with actual events, builds experience that
helps planners to reduce risk and uncertainty in future project assumptions and plans.
For instance most power projects nanced by the World Bank proved to cost more
and take lengthier times to implement than planned, and detailed sensitivity analysis
does not adequately capture or account for such differences [4].
Project analysis: evaluation of risk and uncertainty 173
Table 13.1 Major uncertainties faced by electricity utilities [4]
External uncertainties
national and regional economic growth and its corresponding effect on future
electricity demand,
structure of energy demand and rate of substitution of other fuels by electricity,
unpredictable future uctuations in local and global fuel prices,
insecurity in imported fuel sources,
future environmental regulations and legislation,
technological innovations and development of more efcient and clean plant,
future ination and cost of nancing.
Internal uncertainties
project cost overruns,
project execution schedules and delays,
reliability of the system and availability of generating plant,
system losses,
operation and maintenance costs.
There are many ways to handle and deal with uncertainty and risk. These can be
grouped under the following headings:
(i) delay and defer decisions until the uncertainty is reduced,
(ii) plan and allow for possible short-term contingencies,
(iii) sell risk to others through turnkey projects, long-term fuel contracts, etc.,
(iv) exible strategies that allow for relatively inexpensive changes like designing
the system to allow for possible future fuel conversion, executing the network
to allow for operating at higher voltage, etc.
Therefore recent trends in generation planning try to avoid investing in large units
with long lead times and concentrate instead on smaller sets with short construction
periods and limited investment. This will greatly reduce capital risks of utilities, as
already explained in Chapter 1.
For simple and small projects, uncertainties can be adequately evaluated by a
simple sensitivity analysis, through measuring the response of the IRR or net present
value to predictable variations in the project inputs. Alternatively it may need a full
risk analysis utilising a probabilistic approach to assess the combined net effect of
changes in all variables or the likelihood of various changes occurring together. Such
a probabilistic approach is particularly useful, indeed necessary, in the case of large
capital intensive and risky projects.
Generally speaking there are several procedures for project risk analysis, mainly:
sensitivity analysis, decision analysis, break-even analysis and the Monte Carlo
simulation [5].
174 Economic evaluation of projects in the electricity supply industry
13.3 Sensitivity analysis
Sensitivity analysis involves calculating cash ows under the best estimate of input
variables, and then calculating the consequences of limited changes in the value of
these inputs. It assists the evaluator to identify the variables that signicantly affect the
outcome and correspondingly needs more information and investigation. Sensitivity
analysis is carried out during practically every nancial and economic evaluation of
projects; it is simple and informative. It is a review of the impact that changes in
selected project inputs, costs or benets, or a combination of these, can have on the
projects net present value or IRR. In this case one or more variables are changed
independently or collectively, within reasonable limits (say, 1020 per cent) to see
the likely effect of the change on the net present value of the project and its likely IRR.
Alternatively the aim may be to calculate the change in one variable, like the selling
price per unit or project cost that will reduce the net present value of project benets
to zero. This will indicate the selling price per unit or project cost below or above
which, respectively, it is not worthwhile pursuing the project. Another alternative may
be break-even analysis, to work out values of inputs and outputs that will reduce the
project benets to below the cut-off rate, which is a rate established as a threshold
below which projects should not be accepted. The cut-off rate depends to a large
extent on the riskiness of the project. A project with a high volatility in some inputs
will therefore need a much higher acceptable cut-off rate than a project with almost
sure estimates.
One of the most important exercises in sensitivity analysis is to review the impact
of the discount rate on the projects net present value and its protability. In this
case, and if there is no single rm discount rate, more than one discount rate is tried
and the outcome with each discount rate is described. The UNIPEDE/EURELECTIC
study into the projected cost of generating electricity considers two discount rates,
5 per cent and 10 per cent, each applied with different outcomes [6].
Sensitivity analysis is therefore an essential and easy means of evaluating the
vulnerability of the project to likely future deviation from best-input estimates. It can
also greatly help in assessing the extent of risk in the project, and the particular inputs
that signicantly affect the project outcome. Once these are identied, then a more
careful study should be undertaken of these particular items to enable better estimates
and a rmer calculation of the net present value and the projects IRR. For the electrical
power industry the most important items affecting a projects nancial performance
are the electrical tariff and fuel prices. With the increasing availability of electronic
calculating facilities it has become much easier to undertake many sensitivity analysis
scenarios and to analyse the effect of various parameters on the projects nancial
and economic feasibility.
One of the major weaknesses of sensitivity analysis is that the changes are, most
of the time, ad hoc (10 per cent change in price of fuel or 10 per cent change in
demand, etc.), without regard to the expectancy and probability of these happening.
Such ad hoc assumptions do not assist decision makers to examine the likelihood of
the event. Fuel price changes, in the future, may be much more likely to occur than
other operational costs, therefore dealing with these two on equal terms can lead to
Project analysis: evaluation of risk and uncertainty 175
wrong impressions and conclusions. So also can the effect of a change of one input
on other inputs; a signicant change in fuel prices will not only affect the NPV and
IRR, but will also affect demand, prices and merit order and can cause signicant
implications, which are not captured by sensitivity analysis. What is important is not
only the prospect of change of a fundamental input assumption but also the probability
of this happening and its extent, and also the interrelationship between variation in
one variable and other inputs. Such prospects can only be adequately evaluated by
proper risk analysis.
To demonstrate this, consider a 100 MW CCGT set, ring LNG, that consumes
6000 BTU per kWh generated, at a cost of 2.60 per million BTU. The set will cost
50 million at commissioning and is expected to act as a base-load generating unit at
full load for 7000 hours annually. There is a xed annual cost of 1 million.
With a 10 per cent discount rate, over 20 years, the equivalent annual cost of
investment is equal to
20-year annuity factor
50 million
= 5.87 million.
The xed annual cost of capital and operation will equal
5.87 million +1 million = 6.87 million,
with an annual generation of
100 MW7000 h = 700 GWh.
The xed annual cost per kWh will be
6.87 million 700 GWh = 0.98p.
Fuel cost per kWh is
(2.6 6000)/10
= 1.56p.
Total cost of generation is
0.98 +1.56 = 2.54p kWh
Consider the case of a sensitivity analysis of a possible increase in fuel cost by
20 per cent, then the fuel cost will become 1.872p kWh
and total cost of generation
2.85p kWh
With such a fuel price and operational cost, the set most likely will not remain a
base-load set and correspondingly the energy output of the set and its cost per kWh
will be higher (depending on the position of the set in the merit order). Sensitivity
analysis fails to capture such correlation between fuel cost, energy contribution of the
set and correspondingly system cost. It is only simulation that can give the generation
cost, capture the system effect and evaluate the true economics of investing in such
a plant compared with other alternatives ring other fuels.
176 Economic evaluation of projects in the electricity supply industry
13.4 Break-even point analysis
In all industrial production projects a nancial break-even point analysis is essential
in order to assess the relationship between production volume, production cost and
prots. The break-even point is the level of product sales at which nancial revenues
equal total costs of production; at higher volume of sales nancial prots are gener-
ated. The detailed break-even analysis will vary depending on what type of prots
(gross, net, before or after tax, etc.) and what type of costs (cost of money, cost of
certain input items) it is required to test. It is usual to carry out such testing through
sensitivity analysis in order to demonstrate how variation in different components of
production cost or demand affect this break-even point.
Break-even point analysis is essential in industrial projects. It can be carried out
rather easily by equating xed costs and variable costs to income from sales at a
certain sales level so that
xed (capital and xed operation) costs
+(sales volume variable production cost per unit)
=sales price sales volume.
One important point to remember in break-even analysis is that it has to be carried
out through proper nancial evaluation, like that in Chapter 5, rather than through
nancial accounting statements, which is a common error that most rms fall into.
For example, consider a rm that will invest 10 million to produce a product
that has a market price of 2 per unit and a 0.5 variable cost per unit. The rm
will face 0.25 million xed expenses annually. The business is going to remain for
10 years and the company employs a straight-line depreciation method, where sales
equal production. It is required to nd out the break-even point.
The annual xed costs of the company are
depreciation (10 million per 10 years) 1.00 million
other xed costs 0.25 million
total 1.25 million.
The break-even sales are now calculated according to the earlier equation:
1.25 million +(0.5 volume of sales) = 2 volume of sales
1.25 million = 1.5 volume of sales
break-even volume of sales = 833 thousand units.
Therefore this rm will go into business only if it is guaranteed that its sales will
exceed 833 thousand units, on the average, annually.
This accounting approach basis is quite misleading since it ignores the opportu-
nity cost of capital. As mentioned in Chapter 6, depreciation is accounting cost that
should not go into nancial evaluation. The real cost of money is its opportunity
Project analysis: evaluation of risk and uncertainty 177
cost; assuming that this is 10 per cent, then the equivalent annual cost of the
investment is:
10-year annuity factor
10 million
= 1.627 million
annual xed cost = 1.627 million +0.25 million = 1.877 million
1.877 million +(0.5 volume of sale) = 2 volume of sales
break-even sales = 1251 thousand units.
(This new break-even volume of sales is more than 50 per cent higher than the ear-
lier gure, which displays the importance of nancial evaluation and having proper
assumptions. Depreciation does not reect the true cost of money and it is quite
misleading in evaluation in that it leads to a lower break-even point.)
To assess the effect of production cost per unit, a sensitivity analysis is carried
out by increasing this by 20 per cent, to 0.6 per unit, and measuring the effect on
the break-even sales volume. This will mean increasing the break-even sales volume
into 1341 thousand units, i.e. 7.2 per cent more.
Sensitivity analysis, as has been proven by experience, is not adequate for large
capital-intensive projects. However, it remains a simple and widely used tool for
assessing the risk in project valuation and in drawing the attention of planners to
particular project inputs that warrant special attention, so that these can be investigated
better, or so that certain arrangements are made beforehand, to reduce their risk.
Sensitive analysis through varying the discount rate (the opportunity cost of capital)
can have great impact on the outcome particularly when comparing a capital-intensive
project with limited-future long-term operational cost (nuclear) with less capital-
intensive alternatives, but higher cost of operation (CCGT and coal plant). It is much
wiser to undertake an extensive exercise to nd the right discount rate commensurate
with the risk, as explained in Chapter 4, rather than to undertake a discount-rate
sensitivity analysis, which may lead to confusing results.
13.5 Decision analysis
A more comprehensive approach to uncertainty than sensitivity analysis is decision
analysis [7]. In its simplest form it involves selecting scenarios: the base scenario, an
optimistic scenario and a pessimistic scenario. The base scenario will demonstrate
the most likely inputs and outputs from the point of view of the project evaluator.
The optimistic scenario will incorporate future parameters that are more favourable
to the project success than they appear at the time of evaluation, while the pes-
simistic scenario will have an opposite view expecting that future events may be less
favourable than they appear today. A decision analysis can be undertaken where each
of these scenarios can be assigned an explicit probability and be represented as deci-
sion tree. Aquestion about the discount rate to be applied arises; a pessimistic scenario
will have much less risk than an optimistic scenario, so will the same discount rate
be applied in both cases? This is a valid argument that will be dealt with later.
178 Economic evaluation of projects in the electricity supply industry
Detailed decision analysis involves the construction of a set of mutually exclusive
scenarios of an event, the sum of probabilities of these scenarios adding up to unity.
Only one of these mutually exclusive scenarios must take place. Decision analysis is
a way of dealing with prospects for future variation of key inputs. Each input can have
exclusive scenarios with these scenarios covering all possible future states (N), each
state with a probability (P), such that the sum of all these probabilities equals unity

=1). If the possible values of each input quantity are small, then uncertainty
can be expressed as a discrete probability distribution of the output.
The probability of the input quantities can, in most cases, be better presented
as continuous, rather than discrete, distribution. It is possible, as an approximation,
to express a continuous probability function by a discrete distribution and use the
probability tree approach. But with many input variables, proliferation of the tree
will occur, and this makes the analysis rather cumbersome.
Setting up mutually exclusive scenarios with a probability distribution assigned
to each is a rather difcult task. These are usually based mainly on the judgement of
experts and other project designers. It involves a lot of estimation and future guessing.
Decision analysis is an improvement on sensitivity analysis; however, its weakness
lies in the selection of discrete assumptions and probabilities, which are arbitrary in
many cases. Also the method does not capture the covariation that may exist among
different variables.
Decision analysis, therefore, is a step forward from sensitivity analysis, yet it has
its shortcomings, which have already been explained. However, if the likely input
probabilities are few and discrete and can be presented in a simple decision tree, then
this can assist in better risk evaluation of the project. Such decision trees are very
helpful in sequential decisions. The sophisticated approach to risk assessment is to
characterise the uncertainty in the project inputs by assigning a probability distribution
to each important input and to simulate the project output IRRor net present value
by a probability distribution as described in Section 13.6.
13.6 Risk analysis (the Monte Carlo simulation)
In sensitivity analysis the impact of change of one variable at a time is evaluated;
decision analysis allows the evaluation of the effect of a limited number of plausi-
ble combinations of variables. Risk analysis is the tool for considering all possible
combinations. As already explained, because of uncertainty about major inputs the
selection of a single value for the input variables (as is the case in the deterministic
evaluation) could lead to misleading outputs. Risk analysis is basically a method of
dealing with uncertainty. Recent trends in the electricity supply industry, particu-
larly the growing importance of competition and markets and independent power
producers, have strengthened the need to resort to risk analysis in order to deal
with uncertainty. Uncertainty is characterised by trends, events and developments
that are not known in advance but are likely to happen, and whose occurrence can
affect the outcome of planning decisions. The fundamental risks that are encountered
in the electricity supply industry have already been mentioned. They are primarily
Project analysis: evaluation of risk and uncertainty 179
market (demand growth, future fuel prices, cost of money, tariffs and other income
prospects) and technical (breakdowns and non-availability of plant, technological
change and prospects for future environmental legislation and enforcement). During
project implementation there are also the risks of cost overrun, delays in implemen-
tation and teething troubles in commissioning. Also the changing structure of the
electricity supply industry worldwide is creating uncertainties about regulations, the
introduction of new players, the phasing out of monopolies and possible competition.
For most small projects, sensitivity analysis (or the more sophisticated decision
analysis) can be enough to satisfy the investor as to the vulnerability of the rate of
return to reasonable variations in the values of key inputs of the project, and hence
the risk extent in the investment. However, in the case of more important investment
projects, particularly in newventures with little past experience, a proper risk analysis
has to be undertaken. Risk analysis calls for sophisticated knowledge of expectancy
and probability theory and the undertaking of value judgement.
In the deterministic approach, the NPVand the IRRfor the project were presented
as single gures. In actual fact each is a single point on a continuous curve of possible
combinations of future happenings. Therefore it is much more accurate to calculate
the IRRin a formof schedule (or curve), which will not only give the most likely value
of the IRRbut also the chance of this value happening and the chance of its being lower
(or higher) than the likely value, as shown in Figure 13.1. This analysis would give
the investor a much better knowledge as to the prospect of his investment achieving
the expected return, or any variation of this, with the probability of it happening. This
will not only sharpen the investors knowledge of the protability of the investment
but in some cases it may also affect his choice of the least-cost solution.
The idea of risk analysis is to try to present each of the main values of inputs and
outputs of the project in the form of a probability distribution curve with each event
having a chance of happening. For instance the most likely cost of the project is C,
but the likelihood of this happening is 50 per cent, the chance of it becoming 1.5 C
is 10 per cent, but it is impossible to exceed 2 C, while the prospect of it becoming
0.95 C is 20 per cent and can never be below 0.90 C. Such information will allow the
9 11
Percentage internal rate of return (IRR)
Figure 13.1 Probabilistic presentation of the rate of return (IRR)
180 Economic evaluation of projects in the electricity supply industry
drawing of a distribution curve similar to that in Figure 13.1. Such distribution curves
can be drawn not only for the project cost but also for most of the input variables:
future fuel prices, the project execution time, the cost of operation, the size of sales
and the likely sale price of the output, etc.
There is no precise or standard way of drawing such curves; the curves, however,
present the best-value judgement of the project planners and estimators as to the likely
values concerning these main elements of costs and benets. Such valuation depends
on the estimators value judgement, which is derived from experience and under-
standing of the market and knowledge derived from previous projects. By utilising
the Monte Carlo method in selecting, at random, input sets of these components each
with its probability of happening and calculating the IRR for each combination, and
repeating this a few times, an IRR curve can be established with its peak, indicating
the most likely IRR value and the chance of it happening and also the likely devia-
tion from this return, each with its probability. Thus the extent of risk in the project
becomes clear. A similar curve can be drawn out for the NPV, with each value having
a probability of it happening; the same applies to similar required outputs.
The Monte Carlo simulation is a powerful tool in risk assessment. Besides identi-
fying the important input variables, a probability distribution is assigned to each input
while identifying any relationship (covariance) among inputs. Sets of input assump-
tion are repeatedly drawn from each input distribution. This will lead to outputs
characterised by probability distribution, with the possibility of calculating the mean
outcomes, variances and other required parameters.
The Monte Carlo simulation involves three steps.
Modelling of the project. The complete model of the project will contain a set of
equations, details and data for each of the important input variables (for instance,
in the case of generation system expansion modelling load, generation availability
states, futures set sizes and set costs, maintenance scheduling, reliability criteria and
cost of interruptions). The set of equations illustrates howto describe interdependence
between different inputs and interdependence over time.
Specify probabilities. A probability distribution has to be drawn out for each of
the inputs other than those that are known to have deterministic values (for instance
xed price fuel contracts or turnkey key projects). Such probability distribution can
take one of the shapes specied in Figure 13.2 that is drawn by experts using their
experience and expectations or through knowledge of past performance and data, as
in the case of simulation of generation capacity states. The results are sensitive to the
form of input distribution; therefore, choosing the most relevant distribution is quite
important. Normal distribution is not always the appropriate distribution form unless
there is supporting evidence.
Simulate cash ows and calculate output. The computer samples from each of the
input variables each input value with a probability, calculating the resulting output
cash ows and through them a probability distribution of NPV and IRR.
Such a simulation process is tedious and complicated; however, it has many
advantages. Not only does it lead to better results with the associated probability of
Project analysis: evaluation of risk and uncertainty 181
Value of
the variable
Value of
the variable
Value of the variable
beta distribution
Value of the variable
uniform distribution
Value of the variable
The step rectangular distribution
Normal distribution
Minimum Maximum
Minimum Minimum Maximum
P1 P2 P3 P4
Best estimate
Figure 13.2 Probability distribution curves (to be used in presenting the probabili-
ties of different input variables)
achieving these, it also enables the forecasters and planners to face up to uncertainty
and interdependencies and investigate input values in greater detail. The discipline of
simulation can in itself lead to a deeper understanding of the project.
Once the input distribution curves have been completed, the computer, utilising
the Monte Carlo simulation, generates random values for each of the parameters,
calculates the rates of return (NPV or other required output) in each run, and then
repeats the process with new random inputs. After many runs (say 300) an output
distribution is obtained with a mean and a standard deviation.
Unlike sensitivity analysis, this probabilistic risk simulation gives a complete pic-
ture of the project outputs and their chance of happening, thus quantifying the project
risk. This is not necessarily the true risk that is going to occur in the future, but the
risk that is the best judgement of the project evaluators and appraisers. Therefore it
goes nearer to dene and point out the risks of the project and its output parameters.
182 Economic evaluation of projects in the electricity supply industry
These, together with the mean and standard deviation, are the best denition of the
projects likely output.
One of the most important values of risk analysis is that it assists in reducing the
risk of the project by considering in detail inputs that increase the output risk and
studying these risks with methods designed to minimise them. Sensitivity analysis
can assist in pointing out the inputs that have a major impact on the project output,
therefore risk analysis can concentrate on studying these. It has also to be noticed that
normal contingency allowances have to be incorporated in the probability distribution.
The results of the analysis usually focus on calculating the rate of return.
A few results are expected:
(1) the mean internal rate of return and the standard deviation,
(2) the probability of achieving a minimum return,
(3) the shape of the distribution and the 95 per cent range condence level.
13.7 Consideration in risk analysis
13.7.1 Building up probability distributions
The rst and most important step in risk analysis is to assign to each input variable
a suitable probability distribution. These distributions are based essentially on sub-
jective judgement. The amount of input variables involved depends on the extent of
disaggregation referred to in Section 13.7.2. The subjective judgement of the proba-
bility distribution of each input will involve a small team of evaluators and appraisers
who are familiar with the inputs and their likelihood variations and also with prob-
ability simulation [8,9]. Opinions are exchanged among the team members until a
probability distribution, from among classical probability distributions, is chosen as
being a better t to the case. Of particular importance are the extent of skew and the
probability of the interval. The approach aims at interaction between quantitative and
qualitative judgement. A quantitative judgement involves assigning tentative gures;
these in turn are judged qualitatively and modied, and the process is repeated until
a probability distribution curve of the input is agreed upon, by all those concerned in
the process, as representing the most likely possible distribution.
As explained above the probability distribution to be utilised has to represent the
best judgement of the evaluation and appraisal teams. There are many forms that a
probability distribution curve can take. These are:
step rectangular distribution
discrete distribution
uniform distribution
beta distribution
trapezoidal distribution
triangular distribution
normal distribution.
The form of these probability distribution curves was presented in Figure 13.2.
The choice of the most appropriate distribution curve depends on the judgement
Project analysis: evaluation of risk and uncertainty 183
of the evaluation team. There is tendency to use the normal distribution because of its
neatness. Experience, however, has shown that this is probably not the best distribu-
tion curve in every case. Other forms like the step rectangular or discrete distribution
are also quite useful (sometimes more useful) and easier to formulate.
Two major issues have to be considered in risk analysis: disaggregation and
13.7.2 Disaggregation
Disaggregation refers to the extent of detail in which an input has to be analysed. For
instance, the cost of a power station involves civil works, turbine, generator, boiler,
switchyard, fuel handling and storage. The civil works can be disaggregated into
great detail of foundations, buildings, cooling arrangements, control room building,
storage andworkshopbuilding, etc. Eachitemcanbe disaggregatedintofurther details
involving quantities of cement and concrete, steel reinforcements, aggregates, labour,
other inputs, etc. It is important to understand where to stop disaggregating in order
to construct a reasonable probability distribution for each item, and correspondingly
of the project cost.
Incomplete and inaccurate results usually happen from lack of disaggregation.
Through disaggregation it is possible to obtain better cost estimates, a more realis-
tic demand prediction and a better probability distribution for the inputs. However,
too much disaggregation will make the work of the evaluation team cumbersome in
having to construct too many probability distribution curves. Therefore it is wise to
concentrate on disaggregating those uncertain input items that can have greater impact
on project viability and evaluation.
13.7.3 Correlation
Correlated variables are variables that are likely to move together in a systematic
way. They are not easy to detect and are difcult to measure. They appear in practically
every project and if ignored can lead to the wrong conclusions. In the electricity supply
industry, demand is correlated to economic growth and the tariff; operational costs
are in turn very strongly inuenced by possible variation in fuel prices, this in turn is
correlated with demand and economic activity.
Correlation is often hidden and difcult to detect, also it does not appear in the
deterministic approach. Disaggregation helps greatly in building up and complicat-
ing the problem of correlation, and by limiting disaggregation to an adequate and
reasonable level, correlation can better be dealt with. Also acquisition of more data
and relating inputs can discover serious correlation that may exist and will allow
accounting for this. Correlation is a much more serious problem than the choice of
the probability distribution curve. It is not possible to give a general rule for the elec-
tricity supply industry, particularly the movement of fuel prices and its relationship
with other inputs. Each large project has to be studied separately and its features,
disaggregation and correlation adequately dealt with.
184 Economic evaluation of projects in the electricity supply industry
13.7.4 Effect on the discount rate
In the electricity supply industry different projects have different risks. Investing in
a power station is riskier than investing in transmission and distribution; nuclear and
new technologies power stations (including some renewables) are riskier investments
than conventional power stations. All this can be incorporated in the discount rate,
which can vary in accordance with the extent of risk in the project.
The second consideration is whether a closer study of the project including pre-
senting input variables in a stochastic manner, with disaggregation and appropriate
correlation, will reduce investment risk and hence lead to a reduction in the discount
rate. It has to be remembered that the discount rate signies the risk of the project.
However, in spite of the care in identifying accurately the project inputs (demand,
project cost and fuel prices), risk still exists. The discount rate can never be equal to
the risk-free discount rate, although it will be near to it in the case of fully regulated
electricity distribution utilities where there are frequent tariff adjustments.
Simulation is more realistic in predicting the future performance of the project.
However, there will still be inaccuracies in representing the input variables. Also,
not all variables can be accounted for and be adequately represented in a probability
Therefore it has been advocated that instead of calculating the NPV through
simulation it is sufcient to calculate the IRR and represent it in a probability distri-
bution curve similar to that of Figure 13.1 with a mean and a range containing 95 per
cent of the expected values of the IRR. This will avoid the problem of assigning a
previous discount rate for the project to obtain the NPV. However, if the mean IRR is
computed by simulation with a standard deviation this still has to be compared with a
discount rate that reects the risk of the project as advocated in Chapter 4. Calculation
of the discount rate that considers the reduced risk of the project is required.
13.8 The value of risk management in liberalised markets
Liberalisation intensies competition; this will lead to price volatility and greater risk
[10] to producers. In the past, accidents and increased costs over a short period owing
to unavailability of a low-cost plant were not reected in immediate price increases.
Producers were able to delay reecting their increased production costs in their prices.
There was a time adjustment on prices, which enabled producers to distribute sudden
cost increases over a longer period. Clients who consumed electricity at the time
when the marginal cost of production was the highest paid roughly the same price
as clients who consumed electricity when the marginal cost was at its lowest. With
the advent of competition, this is no longer the case: competition has introduced true
pricing. Tariffs are applied in real-time (producers must submit their supply bids for
the following day), which tends to heighten price volatility.
Indeed, prices can be highly volatile on the spot markets, incurring price risk
for the different players and sparking the need for a new functionrisk management.
As with physical sales, price risk can be hedged in two ways.
Transactions can be made over-the-counter. This is notably the case when there
is no organised market.
Project analysis: evaluation of risk and uncertainty 185
Transactions can be made in organised nancial markets, which offer derivatives
(futures and options). In general, these organised nancial markets are created as
a natural complement to organised spot markets.
The rst example is illustrated by the market that existed until recently in England
and Wales. Owing to the high levels of price volatility on the Pool, the majority
of market participants have contractual relationships in the form of Power Purchase
Agreements (PPA). These can be forward contracts where the supplier agrees to
deliver a certain volume of electricity to the consumer in the future, at a price agreed
in advance. The contract may also be a Contract for Differences (CFD), which is a
purely nancial contract. A supplier and a consumer agree on a price for electricity
to be supplied over a given period (the strike price). If the Pool price is above the
strike price, the consumer pays the supplier the difference between the two prices,
while if the strike price is below the Pool price, the supplier pays the difference to the
consumer. Options are also available.
The second example is illustrated by the Nord Pool. In addition to the spot market
(Elspot), the Nord Pool comprises a nancial market (Eltermin) with a viewto offering
operators heading and risk management services. Eltermin contracts comprise three
major categories; forward contracts, futures contracts and options. These concepts
are explained in detail in Chapter 14.
13.9 References
1 DIMSON, E.: The discount rate for a power station, Energy Economics,
July 1989, 11, (3)
2 AUERBUCH, S. et al.: Capital Budgeting, technological innovation and the
emerging competitive environment of the electric power industry, Energy Policy,
February 1996, 24, (2)
3 HERTZ, D. B.: Risk analysis in capital investment, Harv. Bus. Rev., Sept/Oct
1979, pp. 169181
4 Incorporating Risk and Uncertainty in Power SystemPlanning, The World Bank
Energy and Industry Department, paper 17, June 1989
5 BREALEY, R. A., and MYERS, S. C.: Principles of Corporate Finance
(McGraw Hill, 2000, 6th edn.)
6 Electricity generating costs for plants to be commissioned in 2000, UNIPEDE,
Paris, January 1994
7 SPINEY, P., and WATKINGS, G.: Monte Carlo Simulation techniques and
electric utility resource decision, Energy Policy, February 1996, 24, (2)
8 REUTLINGER, S.: Techniques for project appraisal under uncertainty
(The Johns Hopkins University Press, for the World Bank, 1970)
9 POUIQUEN, L.: Risk Analysis in Project Appraisal (The Johns Hopkins
University Press, for the World Bank, 1975)
10 NYOUKI, E.: Deregulation, competition, price volatility & demand for risk
management on the European electricity market, World Power, 2000
Chapter 14
Risk management in electricity markets
14.1 Introduction
Risk is the hazard to which we are exposed because of uncertainty [1]. Risk is also
associatedwithdecisions. Where there are nouncertainties andnoalternatives, there is
no risk. Decisions that we make can affect these uncertainties and can reduce hazards.
Under regulated markets there were fewer uncertainties and risks because tar-
iffs were almost xed. With deregulation, electric power markets are volatile, prices
change within a short time, and risks can be serious. In the deregulated market of elec-
tric power, electricity is a commodity and consumers have choices, correspondingly
generators are competing among each other. This has created opportunities mainly
for consumers and risks for producers, which need to be hedged.
Trading refers to transactions that take place directly between two parties or
through an organised exchange. Although commodities trading in agricultural prod-
ucts has been established since the middle of the 19th century, it was only in 1996
that electricity future started to be traded in the New Year Mercantile Exchange in
the US.
14.2 Qualifying and managing risk
We have tostart bytryingtoquantifyriskandmethods for reducingandmanagingsuch
risks by hedging or other means. This needs understanding of the risk management
terminology and jargon, which is summarised below.
Robustness, the most fundamental measure of risk, is the likelihood that a par-
ticular decision will not be regrettable. If the decision-makers choice turns out to be
optimal no matter what nature chooses, his choice is robust. (Use of the termoptimal
implies that the decision-maker has a single objective. Robustness is also dened in
multiple-objective situations.) More often, his choice is optimal only for a subset of
natures possible outcomes. Suppose that there is a probability of 0.60 that an outcome
or realisation materialises. Then the choice is robust with probability 0.60.
188 Economic evaluation of projects in the electricity supply industry
Exposure is a measure of loss if an adverse materialisation of uncertainties occurs
for a particular choice. Sometimes exposure can be measured in dollars, but often not.
It is difcult to attach a dollar value to loss and inconvenience for a power breakdown.
A hedge is an option that reduces risk. Derivatives are instruments to achieve this
hedging. A derivative is a nancial instrument (such as futures or options contract). It
is so-called because it derives its value from a related or underlying asset. An under-
lying asset is the specic asset on which a nancial instrument is based. Derivatives
are not securities at all. They are just agreements between two parties with opposite
views on the market to exchange risk. For the hedger, derivatives ultimately help
protect against price increases and assist in lowering funding costs and obtaining
better currency exchange rates in the international nancial markets. Derivatives are
a form of insurance against market swings that affect the value of underlying assets.
Examples of derivative instruments are forwards, futures, options, and swaps [2,3].
Traded options an option gives the rm the right (but not the obligation) to buy
or sell an asset in the future at a price that is agreed upon today. There is a huge
volume of trading in options that are created by specialised options exchanges. For
example, you can deal in options to buy or sell common stocks, bonds, currencies,
and electric power as a commodity.
Futures a futures contract is an order that you place in advance to buy or sell an
asset or commoditylike electricity. The price is xedwhenyouplace the order, but you
do not pay for the asset until the delivery date. Futures markets have existed for a long
time in commodities such as wheat, soyabeans, and copper. The major development
in the 1990s occurred when the futures exchanges began to trade contracts on energy
and electricity (see Section 14.2.2).
Forwards futures contracts are standardised products bought and sold on organ-
ised exchanges. A forward contract is a tailor-made futures contract that is not traded
on an organised exchange. The principal business in forward contracts occurs in
the foreign exchange market, where rms that need to protect themselves against
a change in the exchange rate buy or sell forward currency through a bank. Such
forward contracts are increasingly being used in electrical power.
Traders in derivatives are usually referred to as hedgers. Hedging is taking a
position in one security or asset to offset the risk associated with another security or
asset. They are meant to gain protection and have some control over risk. Hedging
instruments include forward sales contracts, future concepts, swaps and options.
Hedging is meant to reduce risk and improve returns. This is achieved by balancing
the gain/loss (in the physical market with the loss/gain in the derivative market).
Derivatives are the best way to hedge against adverse risk. Two types of hedging
schemes allow protection in falling or raising markets.
Short hedge a short hedge is a commitment to sell a product in the future at an
agreed price. A decline in cash market prices is offset by prots in the futures market.
The opposite applies when prices rise. A short hedge offers protection against falling
Long hedge a long hedge involves a commitment to purchase a commodity
in the future at a xed price. A long hedge locks in the price of the commodity
(gas, electricity). It offers protection against rising prices.
Risk management in electricity markets 189
14.2.1 Forward contracts
certain future time for a specied price.
Price for a forward contract is
F = S e
r(T t )
where F = forward price, S = price of the asset at time t , K = delivery or strike
price, T = time of maturity of the contract, t = current time, r = risk-free rate of
the economy.
Figure 14.1 depicts the prot/loss of a forward contract. The payoff depends on
whether the investor took a long or short position. For a long position, the forward
contract has a prot if the price S
is larger than the strike price K. The contract ends
with a loss otherwise. In contrast, for a short position, the contract makes a prot
if the price S
is smaller than the strike price K. This is because the writer of the
contract receives a price higher at delivery than the current market price.
The forward contract allows customised expiration dates and requires no
performance bond.
14.2.2 Futures contract
A futures contract is an agreement between two parties that has standardised terms
and conditions, where the seller guarantees to deliver an asset at a specied price at
a specied time in the future and the buyer guarantees the acquisition of that asset at
the specied price.
Prices of future contracts are calculated with the same formula above. Therefore
both future and forward priced contracts are similarly priced. The future price of
the derivative depends on the underlying price of the asset, the maturity date of
the contract and the risk-free rate of the economy. In ideal situations and under the
same terms, futures prices are equal to forward prices. However, future contracts
differ from forward contracts, because future contracts have specied maturity dates
whereas a forward contract could have any maturity date. With a forward contract the
outcome is usually currency cash while in futures contract it is a physical deliverable.
Also, futures contracts require a down payment (like a performance bond) forward
contracts require no performance bond.
Profile of profit/loss
long position
Profile of profit/loss
short position
Figure 14.1 Prot of long and short positions
190 Economic evaluation of projects in the electricity supply industry
The following example is kept simple with the purpose of illustrating howa futures
contract is used to hedge the risk in a rising market and how to avoid or minimise
ones losses in a declining market.
An energy company sells electricity in the spot market. The company sells blocks
of 500 MW at an hourly price.
(a) Assumption I: the party sells a futures contract (short hedge) to protect against
falling markets.
(1) Electricity prices fall. Next month, the energy company will be selling
500 MWh in the spot market. The current price is $15 MWh
and in
order to lock in this price, it sells a futures contract of 500 MWh through
the exchange at $15 MWh
for the next month. The company targets
revenue of $7500.00.
The electricity prices fall to $12.5 MWh
. The company receives
from the spot market (500) ($12.5) = $6250.00. At the same time, the
company buys back the futures contract that had a strike of $15 at the new
market value of $12.5, realising a gain of ($2.5)(500) = $1250.00. Total
revenue is $7500.00.
Following the market conditions, the company incurs a loss in the
physical market, which is offset by a gain in the futures market.
(2) Electricity prices rise. The electricity prices rise to $17.5 MWh
. The
company buys back the futures contract that had a strike set at $15 MWh
at a loss of $1250.00 and sells the 500 MWh on the commodity market for
$8750.00. The total revenue is $7500.
(b) Assumption II: the party buys a futures contract to lock in a future price.
(1) Electricity prices rise. An energy broker commits to buy 500 MWh for
February delivery froman energy producer. The broker enters into a futures
contract for $15 MWh
for a total cost of $6250.00.
The energy company buys energy from the spot market at
$17.5 MWh
and sells the electricity futures contract for $17.5 MWh
The energy producer makes a $2.5 MWh
prot in the futures market,
which offsets his loss in the physical market.
(2) Electricity prices fall. A Large Industrial User commits to buy 500 MWh
of rm power that follows the spot market price for the next month. The
user buys a futures contract for $15 MWh
for a total cost of $6250.00.
The electricity prices fall to $12.5 MWh
. The Large Industrial
User buys electricity directly from the spot market. The Large Industrial
User sells its futures contract at a loss of $2.5 MWh
The loss in the futures contract is offset by the gain in the spot market.
14.2.3 Options
An option is a type of contract that gives the purchasing party the right to buy or
to sell for a certain price (called the exercise or strike price) and at a certain date
(called the expiration date T, exercise date, or maturity date). The right to perform a
Risk management in electricity markets 191
nancial transaction has a nancial value called a premium. The buyer of the option
pays a premiumfor the right (but not the obligation) to buy or sell the underlying asset
(unlike the right or obligation to buy or sell a forward or futures contract, options are
more versatile). Only a small percentage (approximately 30 per cent) of all purchased
option contracts is exercised, the remaining bulk of which serves to hedge the exposure
to the changes in the market price.
14.2.4 Swaps
A swap is an agreement between two parties to exchange one set of cash ows based
on a notional amount linked to a oating index in exchange for another set of cash
ows based on the same notional amount linked to a xed index.
Swaps have revolutionised nancial risk management and represent one of the
greatest business opportunities in this area. Following the futures market in popularity,
swaps are greatly utilised in the commodity markets; unlike the participants in a
derivative exchange who have no knowledge of their counterparties and are willing
to extend credit to them over a period of time.
There are xed-xed, xed-oating and oating-oating swaps. The most com-
mon ones are xed-oating swaps, which help a company that takes a loan at an
adjustable interest rate to lock in the rate and thus eliminate any risk. The underlying
asset of a swap could be a currency, interest rate, equity, or commodity.
Fixed to oating commodity swaps are common. An example will be a mining
company that supplies coal to a generation utility. The mining company enters into an
annual swap contract where it agrees to receive from the generation utility monthly
payments based on delivery of 1000 tons of coal per month at the rate of $1 per one
million BTU ($28 ton
In such an arrangement the mining company delivers coal each month with the
spot market price per ton multiplied by 1000 and each month the company receives
$28 multiplied by 1000.
Such an arrangement allows the mining company to receive xed amounts. Simul-
taneously the mining company will deliver its coal at spot market value, which
translates into negative or positive cash ow, as the spot market value is in excess or
less than the xed amount of $28 000.
There are several types of swap.
Commodity swap. This is an agreement between two parties to exchange cash ows
based upon the difference between the xed and oating prices of the same underlying
principal. The exchange is done in a common currency.
Interest rate swap. One party agrees to pay to the other party a cash ow equal to a
xed interest rate on a notional amount. The exchange is done in the same currency.
This is the most common swap.
Currency swap. This formof swap involves exchanging principal and xed-rate inter-
est payments on a loan in one currency for principal and xed-rate interest payment
on an approximately equivalent loan in another currency.
192 Economic evaluation of projects in the electricity supply industry
100 units of gas
at spot price
$1000 100
Energy and
Figure 14.2 Fixed-oating commodity swap contract
Differential swap. This is a swap where a oating interest rate in the domestic cur-
rency is exchanged with a oating interest rate in a foreign currency as applied to the
same notional principal.
There are endless combinations of swaps and other derivatives.
An example of a xed-oating commodity swap contract is shown here. Suppose
that an energy and services company supplies energy to a large industrial customer,
in the form of 100 gas units each month for the next ve years. The energy company
enters into a semi-annual swap contract where it agrees to receive from the industrial
customer a xed monthly charge at the price of $1000.00 per unit in return for 100
gas units supplied. This swap is illustrated in Figure 14.2.
The exchange of payments takes place as follows:
the company delivers gas each month with unit spot market value multiplied by
100 units,
the company receives $1000.00 multiplied by 100 units each month.
This swap allows the company to receive a xed amount, and in return the company
will deliver its product at spot market value which translates into negative or positive
cash ow as the current market value is in excess of, or less than, the xed amount of
Typically, this type of transaction is made through a nancial institution that
has the role of transforming a oating price (spot market) into a xed value. Hedging
allows the risk manager to reduce the risk exposure in highly volatile markets. Futures
and options are often-used tools to manage nancial risk.
14.2.5 Political risk
Political risk is very difcult to hedge. Such risk can come through changes in legis-
lation and environmental agendas. In some cases, as in environmental legislation for
reduction where there is market for emission permits, hedges can be constructed.
The same prospects exist for possible carbon taxation legislation. Political legislation
for closing nuclear plants is a major political risk.
14.3 Decision making
A large part of engineering work involves making decisions [2] of various kinds. In
fact, decision making ranks with innovation in its importance to the design process.
The aim of a decision-making process is to come up with a decision that is optimal in
Risk management in electricity markets 193
some sense i.e., the most cost-effective, giving the longest life, involving the lowest
operating cost, leading to the most aesthetically pleasing product, and so on. Often,
when such decisions are made, the decision maker is confronted with the problem of
uncertainty. Intuition and past experience play a prominent role in the engineering
decision-making process, but as important as they are, they are often insufcient
vehicles to bring us to the best decision. In such cases, a rational approach using
probabilistic tools permits proper modelling and analysis of uncertainty.
In any decision analysis, the set of decision variables should rst be identied
and dened. In a decision-making context, the engineer identies courses of action or
alternatives. Next, a prediction is made of the result of each course of action. For alter-
natives, we predict the initial cost, the maintenance costs, the life, the risk of failure,
and other important variables. Each course of action results in a selection of certain
maintenance policy or, in terms of the decision analysis, results in certain outcome.
Before a decisionis made, we attempt todecide onthe desirabilityof eachoutcome
by attaching some value to it. Finally, we make our decision by selecting the outcome
with the greatest value; i.e., the entire decision-making process can be viewed as an
optimisation exercise.
14.3.1 The decision-making process
Any decision-analysis problem can be broken into four steps: (1) structuring the
problem, (2) assessing the possible impacts of the alternatives, (3) determining the
value structure, and (4) synthesising the information obtained in steps (1) to (3) to
evaluate and compare the alternatives. There are usually several issues that have to be
addressed in any particular problem. In any specic case, the resolution of these
issues may be crucial to success. Therefore, all of these issues have to be addressed in
the decision model. Figure 14.3 summarises the basic steps in the decision-analysis
Establish objectives
and attributes
Describe proposed
alternatives describe existing
Determine magnitude
and likelihood of
impacts of proposed
Evaluate proposed
and conduct sensitivity
Issues Issues Issues
Identify decision
makers and
affected parties
Assess preferences
of decision makers
and affected parties
Figure 14.3 Schematic representation of the components of decision analysis [2]
194 Economic evaluation of projects in the electricity supply industry
approach and shows some major issues related to a technology choice in power
systems [2,4].
14.4 References
1 PEREIVA, M., MCOY, M., and MERRILL, H.: Managing Risk in the NewPower
Business, IEEE Computer Applications in Power, April 2000, pp. 1824
2 Risk Assessment and Financial Management, IEEE TP 137 Winter Meeting,
3 BREALY, R. A., andMYERS, S. C.: Principles of Corporate Finance, (McGraw-
Hill, 2000, Sixth Edition)
SICHERMAN, A.: Decision Framework for Technology Choice, Vol. 1: A
case study of one utilitys coal-nuclear choice, Electric Research Power Institute
Report No. EA-2153, 1981
Appendix 1
Financial evaluation for choice of transformer
This is a real-life example of a detailed analysis for the least-cost choice of a trans-
former. It shows howthe higher price of a facility can be traded against its operational
cost over its life span. The example considers two offers for transformers. The rst
transformer offer is cheaper but it has higher losses, and slightly different payment
conditions. The evaluation considers the overall cost of each alternative, its cash price
plus its discounted cost of losses.
The two transformer offers have the following technical characteristics.
Size (MVA) Voltage (kV) Losses (kW)
iron copper
Transformer A 40 132/33 55 400
Transformer B 40 132/33 76 360
Their quoted prices and payment conditions are as follows.
Price (1000s) Payments (1000s)
on contract on delivery
Transformer A 450 225 225
Transformer B 470 70 400
In both cases the delivery is one year after contract. Commissioning is six months
after delivery. The transformers are assumed to be loaded at 50 per cent of full load
196 Economic evaluation of projects in the electricity supply industry
at the rst two years of service, and at 75 per cent of full load in the following two
years. Afterwards it is fully loaded.
In this example, the expected life of the project is 30 years and a discount rate of
10 per cent is considered.
In such a case and in order to choose the least-cost solution it is required to consider
the total cost of the project over its expected life span. This includes the price of the
two transformers plus their discounted cost of the losses: xed losses (iron losses)
and load losses (copper losses). It is assumed that reliability of the transformers will
be the same, also their maintenance costs; therefore these were ignored from the
It has to be realised that copper losses at any time are equal to full load copper loss
kW (denoted C) multiplied by the square of the transformers utilisation factor, i.e.
C =

rated capacity

Therefore in the case of the rst two transformers their combined annual copper
losses at half load are:
400 kW

20 MVA
40 MVA

= 100 kw.
To work out the annual energy losses, the load factor and shape of the load curve
plays a signicant role. Usually, and for most systems, average losses equal to peak
losses multiplied by (0.15+0.85load factor). With a load factor of 60 per cent this
will be equivalent to 0.66.
Therefore annual losses at half load for the rst two transformers are equal to
100 kW8760 h 0.66 = 578 160 kWh, say 578 MWh.
In order to compute the value of the losses, these have to be multiplied by the
marginal cost of energy at the substation site. This may be signicantly lower than
the tariff if the transformer is part of the utility system. For simplicity, a two-part
energy cost is considered: 3.5 p kWh
during the 16 h of peak and 2 p kWh
the off-peak 8 h. Also as an approximation, costs of all copper losses were calcu-
lated at the peak rate since the vast majority of such losses occur during these 16 h,
and therefore no splitting of copper losses between peak and off-peak hours was
Appendix 1 197
Alternative A Transformers
Year Cost
Losses (MWh) Total losses (MWh)
Iron peak Iron off-peak Copper Peak Off-peak
1 225
0 225
1 321 161 578 799 161
2 321 161 578 799 161
3 321 161 1300 1621 161
4 321 161 1300 1621 161
5 321 161 2313 2634 161
29 321 161 2313 2634 161
30 321 161 2313 2634 161
For the sake of discounting, the base date (year) is considered to be the date of
delivery of the transformers. For accuracy purposes, the losses have to be grouped
at the middle of the year, and since the transformers will be operational six months
from delivery, this means that losses can be grouped annually with respect to the base
date (year), with the rst year losses occurring one year after year 0.
It is much easier, to discount kWh and then multiply the discounted value of these
by the cost. This is what has been done in the two following streams, each stream
detailing the discounted total life span cost of each transformer alternative.
Alternative B Transformers
Year Cost
Losses (MWh) Total losses (MWh)
Iron peak Iron off-peak Copper Peak Off-peak
1 70
0 400
1 444 222 520 964 222
2 444 222 520 964 222
3 444 222 1170 1614 222
4 444 222 1170 1614 222
5 444 222 2081 2525 222
29 444 222 2081 2525 222
30 444 222 2081 2525 222
198 Economic evaluation of projects in the electricity supply industry
Transformer A
Annuity factor for 30 years at 10 per cent discount factor = 9.427
Annuity factor for 4 years at 10 per cent discount factor = 3.170
Annuity factor for 2 years at 10 per cent discount factor = 1.736
Annuity factor for the period 530 years at 10 per cent discount factor = 6.257
Discounted losses
Off-peak = 161 9.427 = 1518 MWh
Cooper (peak) = 578(1.736) +1300(3.170 1.736)
+2313 6.257
= 1003 +1864 +14 472
= 17 339 MWh
Total (peak) = 17 339 +xed peak losses (321 9.427)
= 20 367 MWh
Cost of losses
Cost of peak rate losses = 20 367 10
3.5 10
= 712 845
Cost of off-peak rate losses = 1518 10
2 10
= 30 360
Total cost of losses = 743 205
Total cost of project = 225 000 +(225 000 1.1) +743 205
= 1 215 705
Transformer B
Discounted losses
Off-peak = 222 9.427 = 2093 MWh
Copper (peak) = 520(1.736) +1170(3.170 1.736)
+2081 6.257
= 903 +1678 +13021
= 15 602 MWh
Total (peak) = 15 602 +(444 9.427) = 19 788 MWh
Cost of losses
Cost of peak rate bases = 19 788 10
3.5 10
= 692 580
Cost of off-peak rate losses = 2093 10
2 10
= 41 860
Total cost of losses = 734 440
Total cost of project = 400 000 +(70 000 1.1) +734 426
= 1 211 440
From the above analysis it is clear that the life span cost of the rst alternative
Transformer A is 1 215 705, while that of Transformer B is 1 211 426. Therefore
Transformer B is the least-cost alternative, although it is slightly more expensive.
This real-life example shows how operational costs of almost all energy consum-
ing facilities in the electrical power system play a more signicant role in the overall
life span cost than the investment cost. In this case the operational cost is almost
Appendix 1 199
twice that of the price and therefore more important in inuencing the outcome.
This consideration is still more important in case of generating facilities as shown in
Chapter 5.
An alternative approach
A less accurate, but much more simplied, approach will be possible if the loading
on each alternative transformer is assumed to be constant and at full load.
Utilising the Annual Cost Method (the Equivalent UniformAnnual Cost Method)
of Chapter 5, the annual cost of each alternative will be as follows.
Transformer A
Capital cost annuity factor + cost of losses
Copper losses = 400 kW8760 h 0.66
= 2313 MWh
Iron losses = 55 8760
= 482 MWh (one third of these, i.e. 161 MWh,
at the off-peak rate of 2 p kWh
Cost of losses = (2313 +321) 10
0.035 +161 10
= 92 190 +3220 = 95 410
CRF = 1/annuity factor = 1/9.427
= 0.106
Annual cost of the investment = 450 10
= 47 700
Total annual cost = 143 110
Transformer B
Copper losses = 360 kW8760 h 0.66
= 2081 MWh
Iron losses = 76 kW8760
= 666 MWh (one third of these, i.e. 444 MWh,
at the off-peak rate of 2 p kWh
Cost of losses = (2081 +444) 10
0.035 +222 10
= 88 375 +4440
= 92 815
Annual cost of the investment = 470 10
= 49 820
Total annual cost = 142 635
The same result is achieved, which again shows that Transformer B is the cheaper
alternative. However, this method makes many approximations. The present value
method is the more accurate and should be employed whenever possible.
Appendix 2
The following is a glossary of nancial, economic and technical terms used in this
book as well as few other terms that are of interest. Sources for denition are in
references [1], [2] and [6] of Chapter 3.
Amortisation Gradual repayment or writingoff of anoriginal amount. Depreciation
is a form of amortisation. The Capital recovery factor (see below) is composed of an
interest component and an amortisation component.
Annual equivalent A stream of equal amounts paid or received annually for a
period such that by discounting at an appropriate interest rate it will have a specied
present worth. Determined by multiplying an initial value by the capital recovery
factor for the appropriate interest rate and period. To annualise is to nd the annual
equivalent of a value.
Annuity Investment that produces a level streamof cash ows for a limited number
of periods.
Annuity factor The present value at a discount rate r of an annuity of 1 paid at
the end of each n periods:
annuity factor =


r(1 +r)

The annuity factor is obtained from annuity tables in the Financial References.
Appraisal Analysis of a proposed investment to determine its merit and acceptabil-
ity in accordance with established decision criteria (mostly carried out by banks and
developmental agencies).
Arbitrage Purchase of one security and simultaneous sale of another to give a
risk-free prot.
Basis risk Residual risk that results when the two sides of a hedge do not move
exactly together.
202 Economic evaluation of projects in the electricity supply industry
Benetcost ratio (B/C ratio) Discounted measure of project worth. The present
worth of the benet stream divided by the present worth of the cost stream. Often
abbreviated to B/C, also frequently called the costbenet ratio.
Benets The incremental value of product sales or cost reductions attributable to
an investment. In case of the ESI, benets can sometimes be represented in the form
of kilowatt-hours (kWh).
Beta Measure of market risk.
Bond Long-term debt.
Border price The unit price of a traded good at a countrys border. For exports, the
free-on-board (FOB) price; for imports, the costinsurancefreight (CIF) price.
Break-even point The level of product sales at which nancial revenues equal total
costs of production. At higher volumes of production and sales nancial prots are
Call option Option to buy an asset at a specied exercise price on or before a
specied exercise date (cf. put option).
Cap An upper limit on the interest rate on a oating-rate note.
Capital budget List of planned investment projects, usually prepared annually.
Capital rationing Shortage of funds that forces a utility to choose between projects.
Capital recovery factor (CRF) or equivalent annual cost Can be used to convert
a sum of money into an equivalent series of equal annual payments, given a rate of
interest and total period of time. The CRF for 1 at an interest rate of 12 per cent and
a period of 4 years is 0.3292, as shown in the following schedule.
Principal amortisation + Interest = CRF
Principal Interest CEF (total)
1 0.2092 0.1200 0.3292
2 0.2343 0.0949 0.3292
3 0.2624 0.0668 0.3292
4 0.2941 0.0351 0.3292
1.0000 0.3168
The use of the CRF to compute annual capital charges is generally superior to the
use of accounting depreciation allowances and interest expenses, for project appraisal
CAPM Capital asset pricing model.
Appendix 2 203
Cashow In its simplest concept, this is the difference between money received and
money paid out. As used in benetcost studies, the net benet stream anticipated for
a project. Net benets are available for the service of borrowed funds (amortisation,
interest, and other charges), payments of dividends to shareholders, and the payment
of prot taxes.
CIF The landed cost of an import (cost, insurance, and freight) on the receiving
countrys dock, including the cost of international freight charges and insurance,
before the addition of domestic tariffs or other taxes and fees.
Compound interest Reinvestment of each interest payment of money invested,
to earn more interest (compare with simple interest).
Compounding The process of nding the future value in some future year of a
present amount growing at compound interest.
Constant prices or real prices Prices that have been adjusted to remove general
price ination.
Contingency allowance An amount included in a project account to allow for
adverse conditions that will add to baseline costs. Physical contingencies allow for
physical events and unexpected costs, they are included in both the nancial and the
economic analysis. Price contingencies allowfor general ination; in project analysis
they are omitted from both the nancial and the economic analysis when the analysis
is done in constant (real) prices.
Continuous compounding Interest compounded continuously rather than at xed
Covariance Measure of the comovement between two variables.
Covenant Clause in a loan agreement.
Conversion factor (standard conversion factor) A number, usually less than one,
that can be multiplied against a domestic market price of an item to reduce it to an
equivalent border price. The simple version of the standard conversion factor is the
ratio between a countrys foreign trade turnover before and after import and export
taxes (or subsidies).
Correlation coefcient Measure of the closeness of the relationship between two
Cost of capital Opportunity cost of capital.
Costs Costs are incurred to acquire project inputs such as buildings, electrical facil-
ities and machines, materials, labour, and utilities. In economic evaluation certain
outlays, such as the payment of prot taxes, are costs to the project but not the coun-
try. Such outlays are properly treated as transfers of project surplus rather than costs
for the purpose of calculating net present value or internal rate of return.
Covariance Measure of the comovement between two variables.
204 Economic evaluation of projects in the electricity supply industry
Crossover discount rate The rate of discount that equalises the net present value
of benet or cost streams. Often applied to the cost streams of mutually exclusive
project proposals. At a lower rate of discount, A is superior, whereas at a higher rate
of discount, B is superior.
Current prices or nominal prices Prices that have not been adjusted (deated to
eliminate general price ination).
Cut-off rate A rate of return established as a threshold below which projects
should not be accepted. See Opportunity cost of capital.
DCF Discounted cash ow.
Debt service A payment made by a borrower to a lender. May include one or all
of: (1) payment of interest; (2) repayment of principal; and (3) loan commitment.
Decision tree The diagram used in an analytical technique by which a decision is
reached through a sequence of choices between alternatives. It is also a method of
representing alternative sequential decisions and the possible outcomes from these
Deation The act of adjusting current to constant prices. The arithmetic (division)
is the same as for discounting.
Depreciation The anticipated reduction in an assets value brought about through
physical use or gradual obsolescence. Various methods are used: straight line, declin-
ing balance, accelerated, etc. The important thing to remember is that depreciation
charges do not represent cash outlays and should not be included in nancial or
economic cash ows.
Discount factor Howmuch 1 at a future date is worth today. Also called the present
worth factor and the present worth of 1.
Discount rate A rate of interest used to adjust future values to present values.
Discounting a future value to the present is the exact opposite of compounding a
present value forward to a future value.
Discounted cash ow analysis Analysis based on the net incremental costs and
benets that form the incremental cash ow. It yields a discounted measure of project
worth such as the net present worth, internal rate of return, or net benetinvestment
Discounting The process of nding the present worth of a future amount.
Distortion A distortion exists when the market price of an item differs from the
price it would bring in the absence of government restrictions.
EBIT Earnings before interest and taxes.
Economic prices Also known as efciency prices. Prices believed to reect the
relative scarcity values of inputs and outputs more accurately than market prices,
owing to the inuence of tariffs and other distortions in the latter.
Appendix 2 205
Economic rate of return The internal rate of return of a cash ow expressed in
economic prices. Reduces the net present value of the cash ow to zero.
Equity An ownership right or risk interest in an enterprise.
Exercise price (striking price) Price at which a call option or put option may be
Expected return Average of possible returns weighted by their probabilities.
Externality In project analysis, an effect of a project felt outside the project and
not included in the valuation of the project.
Factor of production The inputs required to produce output. Primary factors of
production are land, labour, and capital; secondary factors include materials and other
Financial leverage (gearing) Use of debt to increase the expected return on equity.
Financial leverage is measured by the ratio of debt to debt plus equity (operating
Financial prices Synonymous with market prices.
Financial rate of return The internal rate of return of a cash ow expressed in
market prices. Reduces the net present value of the cash ow to zero.
First-year return An analytical technique to determine the optimal time to begin a
proposed project. The optimal time to begin the project is the earliest year for which
the incremental net benet stream for a project begun in that year has a rst-year
return exceeding the opportunity cost of capital.
Fixed costs Costs that do not vary with changes in the volume of output.
FOB The free-on-board price of an export loaded in the ship or other conveyance
that will carry it to foreign buyers.
Hedging Buying one security and selling another in order to reduce risk. A perfect
hedge produces a riskless portfolio.
Income statement Anancial report that summarises the revenues and expenses of
an enterprise during an accounting period. It is thus a statement that shows the results
of the operation of the enterprise during the period. Net income, or prot, is what is
left over after expenses incurred in production of the goods and services delivered
have been deducted from the revenues earned on the sale of these goods and services.
Incremental Refers to the change in the production or consumption of inputs and
outputs attributable to an investment project. Measuring project benets and costs on
a with/without incremental basis rather than a before/after basis is essential.
Intangible In project analysis, this refers to a cost or benet that, although having
value, cannot realistically be assessed in actual or approximate money terms.
Interest during construction (IDC) Interest charges occurred during project
execution and normally capitalised up to the point in time when the plant starts
206 Economic evaluation of projects in the electricity supply industry
commercial operation. However, neither interest during construction nor operation is
included in the internal rate of return calculation.
Internal rate of return (IRR) A discounted measure of project worth. The dis-
count rate that just makes the net present worth of the incremental net benet stream,
or incremental cash ow, equal zero.
Liabilities, total liabilities Total value of nancial claims on a rms assets. Equals
(1) total assets or (2) total assets minus net worth.
LIBOR (London interbank offered rate) This is the interest rate at which major
international banks in London lend to each other. LIBIDis London interbank bid rate;
LIMEAN is mean of bid and offered rate.
Marginal productivity of capital The economic productivity or yield of the last
available investment money spent on the least attractive project.
Money terms The monetary prices of goods and services. Distinguished from real
terms, which refer to the physical, tangible characteristics of goods and services.
Mutually exclusive projects Project alternatives that provide essentially the same
output; if one is done the others are not needed or cannot be done.
Net benet In project analysis, the amount remaining after all outows are sub-
tracted from all inows. May be negative particularly in the early years of the project.
The net cash ow.
Net present value (NPV) The sum of discounted future benets and costs at a
stated rate of discount. An absolute measure of project merit.
Net working capital Current assets minus current liabilities.
Nominal Stated as an amount of money. Compare with real.
Non-traded A project input or output that is not traded by a country either because
of its production cost, bulkiness or because of restrictive trade practices.
Opportunity cost Value lost by using something in one application rather than
another. The opportunity cost of employing a worker in a project is the loss of net
output that worker would have produced elsewhere. The concept of opportunity cost
is the corner stone of benetcost analysis.
Opportunity cost of capital The return on investments foregone elsewhere by
committing capital on the project under consideration. Also referred to as the marginal
productivity of capital, a rate of return that would have been obtained by the last
acceptable project. The opportunity cost of capital is normally used as a cut-off rate
in investment decisions.
Option See call option, put option.
Payback period Time taken for a project to recover its initial investment in
monetary terms.
Appendix 2 207
P/E ratio Share price divided by earnings per share.
Perpetuity Investment offering a level stream of cash ows in perpetuity.
Present value Discounted value of future cash ows.
Present worth (PW) (1) The value at present of an amount to be received or paid
at some time in the future. Determined by multiplying the future value by the discount
factor. (2) The sum of the present worths of a series of future values.
Price elasticity Price elasticity refers to the relationship between the percentage
change in the quantity demanded or supplied of an item with respect to a stated
percentage change in the items unit price.
Cross elasticity refers to the inuence of the price of one item on the demand
for another. If a reduction in the price of X leads to increased demand for X and
for Y declines, the two are competitive. Zero cross elasticities indicate perfect
complementarity, and innite cross elasticities indicate perfect substitutability.
Pro forma Projected.
Prot Financial prot is the difference between nancial revenues and costs. Eco-
nomic prot is the surplus of benets over costs when economic prices are used, after
deducting the opportunity cost of capital.
Protection Measures that protect domestic producers from foreign competitors,
including import tariffs, quotas, and administrative restrictions that effectively limit
or prevent foreign competition. Most accurately measured as the difference between
border prices and market prices, after allowing for domestic transfer costs.
Put option Optiontosell anasset at a speciedexercise price onor before a specied
exercise date (cf. call option).
Rate of return Remuneration to investment stated as a proportion or percentage.
Often the internal rate of return. The nancial rate of return is the internal rate of
return based on market prices; the economic rate of return is the internal rate of return
based on economic values.
Real interest rate Interest rate expressed in terms of real goods, i.e. nominal interest
rate adjusted for ination.
Real prices See constant prices.
Return on equity (1) The internal rate of return of the incremental net benet after
nancing. Used as a measure of project worth. (2) Net income divided by equity.
Return to capital The rate of return received by the investor on capital engaged in
a project.
Risk premium Expected additional return for making a risky investment rather
than a safe one.
ROI Return on investment.
208 Economic evaluation of projects in the electricity supply industry
Salvage value (residual value) Scrap value of plant and equipment.
Sensitivity analysis A systematic review of the impact that changes in selected
benets and costs have on a projects net present value of internal rate of return.
Shadow price (accounting price) A price that is computed rather than observed
in a market place.
Simple interest Interest calculated only on the initial investment.
Standard deviation A measure of the dispersion of a frequency distribution.
Obtained by extracting the square root of the arithmetic mean of the squares of the
deviation of each of the class frequencies from the arithmetic mean of the frequency
Striking price Exercise price of an option.
Sunk cost A cost incurred in the past that cannot be retrieved as a residual value
from an earlier investment.
Swap An arrangement whereby two companies lend to each other on different
terms, e.g. in different currencies, or one at a xed rate and the other at a oating rate.
Traded Aproject input or output is said to be traded if its production or consumption
will affect a countrys level of imports or exports, at the margin. A partially traded
item will also affect the level of domestic production or consumption.
Transfer payment Apayment made without receivinganygoodor service inreturn.
Treasury bill Short-termdiscount debt maturing in less than 1 year, issued regularly
by the government.
Unique risk (residual risk, specic risk, unsystematic risk) Risk that can be
eliminated by diversication.
Variable costs Costs that vary with changes in the level of output, such as costs for
Variance Mean squared deviation from the expected value a measure of
variability. Standard deviation is equal to the square root of the variance.
Weighted-average cost of capital Expected return on a portfolio of all the rms
securities. Used as hurdle rate for capital investment.
With and without Refer to the situations with and without a proposed project. In
project analysis, the relevant comparison is the net benet with the project compared
with the net benet without the project. This is distinguished froma before and after
comparison because even without the project the net benet in the project area may
Working capital Current assets and current liabilities. The term is commonly used
as being synonymous with net working capital.
abatement 4, 978
marginal cost of 108
acid deposition 105, 1089
air pollution 104, 10710
amortisation 34, 50, 62, 201
Annual Cost Method 199
annuity factor 389, 40, 50, 623, 198, 201
appraisal 238, 201
current 8, 78
long-term 78
return on 79
atmosphere 99, 109
polluted 104
balance sheet 76, 78
bankers evaluation 578
base year 31, 367, 45, 61, 72, 81, 197
discounting to 82
investment cost in 90
benet/cost ratio 679, 202
benet stream 34, 76
benets 37, 456, 89, 91
calculation of 59, 65
compounded 39
economical 59
environmental 98, 1023, 108
evaluation of 57, 812
nancial 59, 89
monetary 81
net 206
betas 4850, 52, 54, 202
bonds 458, 188, 202
index-linked 52
performance 189
borrowing 46
cost of 45, 53
break-even analysis 174, 1767, 202
budget decit 46
California 1478, 1502, 161, 164
capital 17, 21, 23, 68
availability of 456
equity 75
investment 52, 68
marginal productivity of 44, 206
opportunity cost of 32, 35, 43, 46, 51,
534, 59, 61, 65, 69, 82, 177, 203,
real cost of 523
return to 207
structuring 523
working 59, 80, 208
see also CAPM; CRF; WACC; also
following entries prexed capital
capital gains 47
capital intensity 2, 6, 9, 12, 23, 28
coal-red plants 15
environmental technologies 98
large private-sector investments 88
nuclear power stations 45
capital investments 2, 46
projects and 1417
CAPM (capital asset pricing model) 48, 52,
54, 202
carbon 99, 103, 11327
sequestration measures 98, 106, 120
zero emissions 13, 10910
carbon dioxide 6, 9, 97, 104, 1067,
10910, 115
reducing emissions 13, 11618
separation membranes 1223
cash ows 50, 57, 74, 191, 203
accounting for ination in 357
discounted 31, 334, 204
future 34, 51
210 Index
cash ows (contd.)
long-term 34
monetary/nominal 35
CCAs (climate change agreements) 120
CCGT (combined cycle gas turbines) 5, 7,
13, 29, 49, 60, 63, 1067, 114, 175,
investment cost 812, 124
CCL (Climate Change Levy) 11920
CDM (Clean Development Mechanism)
115, 11718
CERs (Certied Emission Reduction) units
CFBs (circulating uidised beds) 8
climate change costing 10911, 11620
see also IPCC; Kyoto; Rio
coal 5, 13, 45, 49, 60, 812
border price of 923
clean 107
environmental impact 99
health hazard 104
low-quality 88, 91, 93, 97, 103, 106
subsidised 90
COI (cost of illness) approach 107
commissioning 589, 61, 63, 71, 73, 82
competition 45, 145, 148, 152, 160, 179,
attempts to introduce 161
benets of 150
real free-market 167
compound factor 32, 36, 203
consumer surveys 141
consumption 87, 98, 106, 168
primary 10
reducing 169
contamination 105
contingencies 713, 203
forward 152, 185, 1889, 191
futures 154, 185, 18891
swap 1912
see also CFD
corporatisation 5, 145, 161
correlation 183
cost-benet analysis 98, 1023, 1334
cost estimation 713, 97112
cost-of-living index 47
costs 9, 267, 37, 73, 75, 83, 129
ancillary 23
annual 624, 72, 199
borrowing 45, 53
capital 7, 34, 434, 523, 62, 73, 75, 106
climate change 107
consumer 1401
economic 22, 84, 90, 94
environmental 88, 98, 1023, 10711
evaluation of 57
nancial 22, 58, 89, 98
xed 63, 175, 205
interruption 138, 1402
investment 36, 43, 45, 58, 812, 90,
1067, 151, 177
life-cycle 43
marginal 108, 110, 164, 196
power quality 139
production 634, 93, 1767, 184
running 634
social 84, 98, 105, 110, 134
sunk 74, 208
variable 208
see also benet/cost ratio; least-cost
solutions; operational costs;
opportunity costs; WACC; also
entries above prexed cost
CPM (critical path method) 27
CRF (capital recovery factor) 3940, 63,
199, 202
currency 94
convertible 93
swaps 1912
cut-off rate 44, 174
damage 98, 102, 105, 10710
damage functions 141, 143
debt 46, 523, 76
long-term 78
debt/equity ratio 52
decision analysis 1778, 1934
decision making 456, 74, 178, 1924, 204
accuracy in 64
day-to-day 60
major impact on 58
demand 27, 97, 109, 124, 141, 147, 174, 183
future 23, 26
gradual increase in 170
peak 136, 151
see also DSM
depreciation 50, 69, 745, 78, 1767, 204
deregulation 4, 16, 21, 1478, 152, 1679,
derivatives 188, 192
deterministic approach 172, 1789, 183
digital economy 138, 1645
disaggregation 162, 166, 1823
disbursements 25, 27, 72
discount factor 323, 367, 60, 198, 204
Index 211
discount rate 27, 324, 435, 55, 196, 204
calculating 4552
controlling the value of 523
environmental impacts and 1023
xing 66
IRR and 82
multiple 54
nominal 36, 73
opportunity cost of capital as 82
real 356, 48, 52
risk-free 184
sensitivity analysis and 1745, 177
social 65
taxation and 501
discounting 27, 3142, 65, 81, 83, 88, 134
base year 82, 197
distortions 89, 204
market 5
price 88
distribution 91, 133, 135
developing countries 16
marketing 162
transmission and 5, 1516, 104, 134, 146
see also probability distribution
distribution curves 180, 1823
dividends 75, 77, 80
uctuations 47
dose-response functions 1078
DSM (demand side management) 9, 21,
earnings see EBIT; income; P/E ratio
EBIT (earnings before interest and tax) 789
economic analysis 26, 90
economic evaluation 58, 73, 75, 8795, 102
detailed 1348
quality of power 1389
efciency 7, 12, 21, 59, 68, 109, 114
allocative 87
domestic energy 113
dynamic 88
economic 14, 878
generating plant 56, 8
investment 4, 160
production 87
thermal 107
efciency-in-use measures 98
efuent disposal 1045
digital economy and 1645
global energy scene and 10
health and environmental effects 1034
trading 14557, 162, 166
transportation of 1612
world economy and 1012
electricity generation 6, 8, 41, 45, 48, 83,
climatic change agreements and 11620
costing/costs 84, 174
emissions 106
emissions-free 1201
environmental cost 10711
evaluation of investment in 13943
frequency and duration 137
future fuels 1314
future technologies 1213
global 5, 14
health impacts 104
investments and projects 1415, 29, 63
non-fossil-fuel 98, 1246
nuclear 489, 120
sources of investment funds 1617
system adequacy 1345, 13940
thermal 5, 48, 97, 105
electricity production see power production
emissions 7, 99, 106, 116
abatement of 4, 98
anthropogenic 105
fossil-red plant 104
low 1201
reducing 13, 98, 106
trading 116, 11820
zero 13
curtailed 169
global 10, 109
hydro 1415, 74, 103, 105
local sources, pricing 90
non-commercial 10
renewable 1314, 1045, 113, 1201,
126, 167, 184
solar 14, 105, 1256
substituting 98
wind 14, 1045
see also IEA; nuclear energy; PEL; TPER
England and Wales 148, 161
Electricity Pool 14950, 185
environmental concerns 4
and cost estimation in project evaluation
and efciency of generating plant 56
and growing importance of natural gas 6
unpredictable events 13
environmental cost 10711
environmental evaluation 102
212 Index
environmental impacts 2, 98100
detrimental 91, 102
different generation fuels 1012
discount rate and 1023
local 1045
measures to reduce 13
regional 1056
serious 28
environmental protection facilities 15
equity 478, 53, 57, 745, 205
return on 79, 207
shareholder 78
Equivalent Uniform Annual Cost Method
ERR (economic rate of return) 88, 102
ERUs (Emissions Reduction Units) 11718
European Commission
ExternE project 101
Single Market Directive for Electricity
(1999) 152
expansion projects 83
external factors 172
externalities 23, 8791, 101, 205
FBC (uidised bed combustion) 13
feasibility 223, 174
FERC (US Federal Energy Regulatory
Commission) 147
FGD (ue gas desulphurisation) 1089
nancial analysis 26, 90
nancial evaluation 5770, 73, 75, 879, 91,
detailed 1348
quality of power 1389
nancial ows 31
future 27
nancial statements 75, 83
estimation of 76
nancial performance and 768
nancial ratios 7880
ow of funds 801
pro forma 69, 76, 81
fossil-red plants 1034, 106
clean 1213
frequency and duration method 137
fuel cells 9, 123, 167
fuels 23, 88, 139
cleaner 4, 108
different generation, environmental
impact of 1012
electricity generation 1214
price of 54, 76, 78, 174
real outlay for 76
subsidies 89, 90
futures 1545, 18891
gas separation membranes 1223
gas-turbine development 123
see also CCGT
gasication technologies 1212
generating plant efciency 56
geothermal power 104
global warming 9, 978, 104, 106, 10910,
115, 121
potentials 99, 101
goods and services 87, 89
non-traded 923
payment for 90
green energy surcharges 167
greenhouse gases 6, 97, 99, 104, 10910,
114, 117
direct national reduction 115
trading systems 119
verication 118
growth 15, 78, 1567
electricity-based innovation and 164
energy use and 10, 12
health 98, 102
and environmental effects of electricity
and safety 99
hedging 154, 187, 1902, 205
long/short 188
HVDC (high voltage direct current) 104,
hydrocarbons 99, 1034
hydro-electric power 1416, 74, 103, 105
IEA (International Energy Agency) 10, 116
IET (International Emissions Trading) 116
IGCC (integrated gasication
combined-cycle) 13, 122
income 35, 65, 778, 176
future 31
national 90
operating 8
pro forma statement 69
real 32
income statement 756, 801, 205
inefciency 15960
ination 31, 44, 52, 69, 713,
accounting for in cash ows 357
expected 756
methods independent from 81
Index 213
inputs 174, 182
interdependence between 180
non-traded 91, 934, 206
traded 913
intangibles 91, 98, 205
interdependence 1801
interest rate 33, 3940, 734, 203
choice crucial 45
depreciation with 745
oating 192
market 656
real 52, 207
risk-free 467
swaps 191
see also EBIT
interruptions 12931, 1334
cost of 138, 1402
momentary 138
serious 135
investment 2, 1317, 267, 50, 723
annual cost of 177
benets exceed opportunity cost of 82
business projects 46
capital 8, 14, 40, 45, 102
efciency of 4
evaluation of 13943
incentives for 170
measuring worth of 658
premium on 32
returns on 446, 58, 69, 208
sunk 74
IPCC (International Panel on Climate
Change) 110
IPPs (independent power producers) 21, 29,
147, 153
IRP (integrated resource planning) 23, 88
IRR (internal rate of return) 43, 657, 69,
736 passim, 102, 172, 1745,
1789, 206
discount rate equal to 82
expected values of 184
nancial 83, 88
incremental 83
measuring the response of 173
probability distribution of 180
JI (joint implementation) 11517
Johannesburg (World Summit on Sustainable
Development, 2002) 115
Kyoto Protocol (1997) 4, 9, 11315, 117,
least-cost solutions 26, 5965, 69, 81, 878,
140, 172, 1956
externalities and 91
leverage 789, 165, 205
liabilities 29, 78, 206
short-term 79
liberalisation 9, 1478, 151, 154, 161, 166,
opportunities presented by 1624
LNG (liqueed natural gas) 6, 15, 108, 175
load shedding 136, 168
loans 25, 46, 578, 756, 89
xed-interest 52
foreign 90
local environmental impacts 1045
LOLE (loss-of-load expectation) method
1323, 1356
losses 16, 47, 5960, 139, 199
annual 196
peak rate 198
maintenance 1356, 164, 196
see also O&M
management 23, 27
demand 4, 9, 21, 1679
risk 155, 162, 167, 18494
marginal productivity 44
market economies 4, 88
market portfolio 48
markets 7, 92
demand responsiveness 1689
deregulated 1478, 152, 1679
nancial 47, 185
foreign exchange 188
imperfections in 89
international 93
liberalised 9, 1478, 151, 154, 161,
negawatt 1689
oligopolistic 164
spot 185, 1902
cost of 51
time value of 3142
monopolies 28, 89, 15960, 164
government-owned 148
phasing out of 179
Monte Carlo simulation 173, 1802
natural gas 8, 15, 60, 1034, 106, 15960
see also CCGT; LNG
214 Index
NETA (New Electricity Trading
Arrangements) 14850
NGC (National Grid Company) 150
nitrogen oxide 6, 97, 99, 1038 passim, 119
non-fossil-fuel power generation 98, 1246
non-traded items 89, 934, 206
Nordic market 153
see also Denmark; Finland; Norway;
North America 121, 141, 143, 153
NPV (net present value) 345, 58, 657, 76,
1745, 178, 181, 184, 206
positive 82
probability distribution of 180
see also PVRR
nuclear energy 1315, 28, 456, 489, 103,
investment cost 81
prospects for 124
O&M (operation and maintenance) 8, 155
OECD countries 10, 12, 1417, 88, 1245
exchange rates 89
OFGEM (Ofce of Gas and Electricity
Markets) 146, 148
oil 13
crises (1970s) 4
oligopolies 159, 164
OPEC (Organisation of
Petroleum-Exporting Countries) 13
operational/operating costs 8, 34, 37, 43, 46,
58, 60, 62, 64, 78, 106, 1745
annual running 63
opportunity costs 32, 35, 43, 46, 51, 534,
59, 61, 65, 69, 75, 82, 177, 203, 206
options 1545, 169, 185, 188, 1901, 202,
output 44, 59, 63, 81, 125, 175, 1801
misleading 178
risk of 182
traded 923
over-the-counter transactions 184
owners evaluation 578
particulates 6, 97, 99, 1067
carcinogenic 104
payback period 68, 207
P/E (price-earnings) ratio 7980, 207
PEL (percentage energy loss) index 1378
PERT (project evaluation and review) 27
PFBC (pressurised uidised bed
combustion) 13
photovoltaic systems 104, 1256
planning 28, 723, 178
nancial 81
system, reliability 1324, 1403
see also IRP
political risk 192
pollution 7, 978
air 104, 10710
control of 4
global 99
irreversible, long-term 105
power generation see electricity generation
power production 2, 6, 14, 41, 81, 83
global 912
power stations 74, 83, 92, 94, 109
CCGT 29, 49, 63, 812, 114, 124, 175,
coal-red 5, 15, 445, 60, 82, 88, 91, 97,
1036, 177
cost of 87, 183
hydro-electric 16, 103
improvements in 59
investment in 50, 184
natural gas 104
new and efcient 90
nuclear 44, 46, 489, 54, 60, 81, 103,
105, 120
oil-red 1035
steam 6, 63
thermal 60, 105
see also virtual power plants
PPA (Power Purchase Agreements) 185
predictions 26, 193
pre-feasibility stage 223, 27
premium 32, 4750, 52, 191, 207
prices 54, 76, 78, 125, 152, 164, 169
base-year 45, 61
border 8894, 202
constant 59, 203, 207
economic 204
xed 188, 191
future contracts 18990
indexed 154
movement of 183
shadow 889, 914, 208
see also P/E ratio
privatisation 17, 21, 65, 1601
probabilistic approach 173
probability distribution 17880
building up 1823
prot/investment ratio 68
Index 215
prot/loss statement 75
protability 4, 27, 589, 61, 65, 68, 76, 87,
174, 178
nancial 88
investors knowledge of 179
owners evaluation of 69
prots 75, 79, 154, 1889, 207
allocation of 76
long-run 164
retained 778
project analysis 17185
project development
evaluation stage 279
investment phase 267
operational phase 27
post-operation evaluation 278
pre-investment stage 227
capital investments and 1417
exible mechanisms 11718
selection and evaluation 212, 289, 34
PURPA (Public Utilities Policy Act, US
1978) 147
PV (present value) 33, 3940, 51, 602, 64,
annual cost and 63
see also NPV
PVRR (present-value revenue requirement)
rate of return 32, 46, 52, 181, 207
compounded 39
economic 205
nancial 76, 205
pre-tax 51
see also ERR; IRR
RECs (regional electricity companies) 48,
refurbishment 74
regional environmental impacts 99, 1056
regulation 25, 4950, 160
regulators 5, 1612
need for 16970
rehabilitation 78
reliability 1, 59, 12944
renewables 1314, 1045, 113, 1201, 126,
167, 184
replacement values 78
repowering 7, 8
reserves 77
residual values 58, 61
respiratory disease 103
restructuring 4, 17, 15961
retrotting 78, 107
returns 8, 17, 31, 48, 58
compounding 33
expected 22, 205
real 32, 39, 44, 467, 50, 53
risk-free 52
simple 33
see also rate of return
risk 26, 312, 45, 54, 80, 155, 166
evaluation of 17185
nancial 22, 26
premium to compensate for 4750, 52
transferring 53
risk analysis 17884
risk assessment 54
risk management 155, 162, 167, 18794
value of, in liberalised markets 1845
RRM (Revenue-Requirements Method) 53
sag events 1389
SCF (standard conversion factor) 934
security 29, 88, 93, 1201, 130
sensitivity analysis 1748, 182, 208
short-term securities 78
shortages 12931, 141
cyclical 169
solar energy 105, 1256
spot markets 185, 1902
standard deviation 182, 184, 208
stock exchanges 478, 76
strike price 169, 185, 205, 208
subsidies 5, 16, 88, 92
fuel 8990
hidden 160
reduction of 145
sulphur dioxide 6, 90, 97, 99, 1039 passim,
119, 192
sustainable development 16
swaps 1545, 188, 191, 208
commodity 191
currency 191
interest rate 191
system adequacy 1345, 13940
system effect 28
system linkages 835, 88, 91
take-or-pay clauses 21
tariffs 16, 25, 28, 36, 53, 64, 81, 98, 179
applied in real time 184
appropriate 88
xed 187
rebalancing of 5, 145
216 Index
taxation 25, 45, 523, 69
carbon 120
depreciation and 75
discount rates and 501
energy/carbon 13
see also EBIT
technological change 278
gradual 4, 12
technology 13, 28, 108, 194
add-on 106
clean fossil-fuel-based 107, 1213
environmental 98
future electricity generation 1213
gasication 1212
see also IT
timing 26, 3142, 82, 139
tolling services 156
topping cycle 13
TPA (third-party access) 162, 166
TPER (Total Primary Energy Requirements)
transfer payments 8890, 208
transformers 133, 1959
treasury bills 48, 208
unbundling 5, 145, 160
uncertainty 17185, 187, 193
UNIPEDE (Union Internationale des
Producteurs et Distributeurs
dEnergie Electrique) 41, 46, 83,
140, 174
United Kingdom
carbon emissions 106
cost of emissions 107
Emissions Trading Scheme 11920
energy trading 14650, 153
market portfolio 48
risk premium 48
Treasury 46
White Papers (1978/2000) 46, 149
United Nations 88
IPCC (International Panel on Climate
Change) 110
UNFCCC (Framework Convention on
Climate Change,
Rio 1992) 11415, 117
United States 106, 120, 146
annual cost method 64
electricity trading 1478, 154
energy policy 113
natural gas sold online 147
New Year Mercantile Exchange 187
value chain 162, 166
value judgment 179
cost of interruptions 1401
future and past 37
present 3741
see also PV
viability 23, 27, 67, 78, 183
virtual power plants 9, 126
virtual utility 167
volatile organic compounds 104
volatility 169, 1845
VOLL (value of lost load) 143
voltage sags 138
voluntary load curtailment 168
WACC (weighted-average cost of capital)
WASP (Wein Automatic System Planning)
way leaving 9
WDA (writing down allowance) 50
wet scrubbers 106
wind power 14, 1045, 1245
World Bank 17, 25, 46, 88, 172
WTP (willingness to pay) methods 107,
110, 141