REVIEW OF DRIVERS FOR TRANSMISSION INVESTMENT DECISIONS

701
REVIEW OF DRIVERS FOR TRANSMISSION
INVESTMENT DECISIONS
WORKING GROUP
C1.15
SEPTEMBER 2017

Members
A. SLEATOR, Convenor IE M. DUARTE, Secretary IE
C. DENT GB G. DE SAINT-MARTIN FR
L.M. DE SOUSA CARIJO BR D. D’HOOP BE
N. FUJISE JP A. ILICETO IT
N. PUSHPARAJ AU S. UTTS RU
G. WESTERBERG NO
WG C1.15
Copyright © 2017
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REVIEW OF DRIVERS FOR
TRANSMISSION INVESTMENT
DECISIONS
ISBN : 978-2-85873-403-0

REVIEW OF DRIVERS FOR TRANSMISSION INVESTMENT DECISIONS
3
EXECUTIVE SUMMARY
OVERVIEW
Traditionally, investment in transmission infrastructure has been driven primarily by security of supply and reliability
criteria that set the technical standards to which a transmission network is planned. With de-regulation and the
evolution of electricity markets; the increase in renewable generation penetration and the drive to combat climate
change; and the growing influence of socio-economic and political factors, the investment decision-making
environment for transmission infrastructure is changing.
In this context, the objective of the analysis undertaken was to review the rationale for transmission investment
decisions; to establish the role of technical planning criteria in investment decisions; and to identify the growing
trends in investment drivers. This was done using data on technical planning criteria and transmission investment
decisions provided by utilities from across the world responding to a detailed survey. The analysis took account of
regulatory and market environments.
APPROACH
In total, 24 responses to the survey questionnaire from 22 countries covering 200 transmission projects and
accounting for c. € 31 billion in capital investment were received. Responses were grouped on a regional basis which
is shown in the Figure below:
The industry structure in the majority of responses was an unbundled environment with only one sixth of the
responses from an environment where there was a vertically integrated utility (VIU).
The majority of Transmission System Operators (TSOs) were in state ownership, i.e. 18/24.
LEGEND
Africa / Middle East
Americas – North
Americas – South
Asia – Pacific
Europe
Responding Country

4
The majority of operators also owned the assets either as a TSO or in a VIU.
Based on system demand, the sizes of systems from the respondents were approximately balanced among small
(i.e. less than 10GW), medium (i.e. from 10GW to 40GW) and large (i.e. greater than 40GW).
ANALYSIS
The analysis identified the main reasons for investment and the role of technical planning criteria in identifying the
need for investment.
Main reasons for Investment
The majority of capital projects undertaken were expansion, new builds accounting for 86% of the list of projects
compiled. The remaining 14% comprised refurbishment or other, such as upgrades.
The main reason given for expansion or new build projects is security of supply (69%), followed by new connections
(generator and demand), generation integration and economically motivated projects. Regardless of the ownership
model, security of supply was the main reason for investment. The majority of projects (i.e. 69%) had multiple
reasons as justification.
The main drivers of refurbishment projects were the replacement of assets at the end of their useful life (50%) and
the upgrade of assets (36%).
Investing on a long-term strategic basis is a factor (i.e. 134 out of 200 investment decisions) across all the investment
categories. Very few projects are driven by a minimum incremental approach to investment. This is especially true
for the Asia-Pacific region (i.e. 33 out of 36 projects are long-term strategic).
Consideration of statutory planning processes has a significant impact on the reinforcement option for all project
categories. With the exception of the Americas, site access; local opposition; and statutory planning processes are
factors frequently having an impact on the reinforcement option.
Novel or unconventional transmission technologies; equipment obsolescence are assessed to have a low influence
on the investment option for all project categories. Financial factors play a significant role in the investment decision
in Africa and the Middle East but are not cited as a significant factor in the other regions.
Role of the Technical Planning Criteria
Compliance with Technical Planning Criteria is cited as the primary determinant of reinforcement need by
respondents. Compliance with the Technical Planning Criteria also determines the timing of reinforcements.
Some respondents differentiated between types of investments, such as statutory investments and economic
investments. For those respondents, statutory investments refer to those necessary to ensure System Operator
licence obligations are met; and economic investments refer to those that reduce overall costs and not required to
meet licence obligations. The Technical Planning Criteria were the primary determinant of reinforcement need for
all cases except those considered to be economic in nature.
The choice of overhead line (OHL) or underground cable (UGC) is not directly addressed in the Transmission Planning
Criteria. According to respondents, the use of UGC is primarily used to mitigate constraints or at lower voltages,
with the primary technology choice being in favour of OHL technologies.
Respondents differentiated between deterministic and probabilistic assessment methods: Investments to meet
minimum redundancy, quality of supply and stability standards are assessed using deterministic methods.
Probabilistic methods to varying degrees are made use of to supplement deterministic methods by several TSOs.

5
The majority of respondents indicated that deterministic methods were used to evaluate the need for reinforcement
with a significant number indicating that both methods were made use of, depending on the situation.
Future Expectations
The questionnaire sought information on changes expected in the future.
The majority of respondents don’t expect a change in industry structure. Of the 12% that do, the changes relate to
changing vertically integrated utilities to facilitate independent power producers and renewable generation sources.
Respondents gave an indication of a pipeline of future projects. The majority of future developments are expected
to relate to new HVAC overhead lines and new HV stations. The main driver of future reinforcement is security of
supply.
Suggested Future Work
Suggested future work has been identified in the following areas:
 Changes to transmission system planning criteria
 The role of future demand growth
 The role of power system size
 Cost benefit analysis
 The role of strategic investments in buying an option to offset future uncertainty
 The impact of micro grids on future investment in main transmission grid
Work on cost benefit analysis has progressed significantly since the survey was undertaken and an update on this is
given.

6

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TABLE OF CONTENTS
EXECUTIVE SUMMARY..............................................................................................................................................3
OVERVIEW .......................................................................................................................................................................................................3
APPROACH.......................................................................................................................................................................................................3
ANALYSIS..........................................................................................................................................................................................................4
Main reasons for Investment......................................................................................................................................................................4
Role of the Technical Planning Criteria ...................................................................................................................................................4
INTRODUCTION.........................................................................................................................................................9
CONTEXT ..........................................................................................................................................................................................................9
COMPLEMENTARY WORK OF OTHER WORKING GROUPS...............................................................................................................9
METHODOLOGY.................................................................................................................................................... 11
QUESTIONNAIRE.......................................................................................................................................................................................... 11
COLLATION OF INFORMATION............................................................................................................................................................... 11
INTERPRETATION OF INFORMATION...................................................................................................................................................... 11
ANALYSIS................................................................................................................................................................. 13
RESPONSES RECEIVED................................................................................................................................................................................ 13
INVESTMENT DRIVERS FOR PROJECTS................................................................................................................................................... 18
ROLE OF THE TECHNICAL PLANNING CRITERIA................................................................................................................................... 30
FUTURE EXPECTATIONS.............................................................................................................................................................................. 33
CONCLUSION......................................................................................................................................................... 37
MAIN REASONS FOR INVESTMENT......................................................................................................................................................... 37
THE ROLE OF THE TECHNICAL PLANNING CRITERIA........................................................................................................................... 38
SUGGESTED FUTURE WORK .................................................................................................................................................................... 38
ACKNOWLEDGEMENTS........................................................................................................................................ 41
ANNEX 1: TERMS OF REFERENCE........................................................................................................................ 43
ANNEX 2: QUESTIONNAIRE TEMPLATE ............................................................................................................. 44
ANNEX 3: QUESTIONNAIRE RESPONSES.......................................................................................................... 54
ANNEX 4: GLOSSARY ........................................................................................................................................... 55
ANNEX 5: DATA SUMMARY................................................................................................................................. 56

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INTRODUCTION
Study Committee C1 has a strategic plan, vision and focus to anticipate and plan a system that best fits the paradigm
shift brought about by rapid evolution in generation patterns and economics, demand response, Information &
Communications Technology (ICT), and in social, environmental, regulatory frameworks and expectations.
This Working Group was set up to review the drivers for transmission investment decisions and the role of technical
planning criteria in transmission investment. The context was the changes in the electricity industry environment
e.g. de-regulation, evolution of electricity markets, renewable generation, climate change, difficulties in building
electricity infrastructure.
CONTEXT
Traditionally investment in transmission infrastructure development has been driven by planning reliability and
security criteria, called Technical Planning Criteria in this brochure. The concept of the Working Group was to review
recent transmission investment decisions and establish the main reasons for investment and the role of the Technical
Planning Criteria.
With de-regulation, evolution of electricity markets, increase in renewable generation, the drive to combat climate
change by mechanisms including energy efficiency initiatives and micro-generation, the decision making environment
in transmission development investment is changing.
Drivers of and factors influencing transmission investment decisions could include technical criteria, economic criteria,
congestion management, facilitating market integration and relieving market constraints, operational criteria,
strategic considerations, environmental aspects, societal aspects and risk assessment. The drivers could also include
political decision making and urbanisation which lead to undergrounding of existing and new power lines based on
aesthetic and health and safety issues.
Investments may be made based on short-term concerns and a minimal incremental approach or be made on a
long–term more integrated strategic basis. The regulatory environment and ownership of the decision making
company may also influence the approach to investment decision making.
COMPLEMENTARY WORK OF OTHER WORKING GROUPS
There are six other Working Groups that have published or are in the process of publishing Technical Brochures in
2016 and 2017 that deal with issues relating to distribution side generation, planning and development. These six
WGs complement each other and focus on different aspects of the same subject. The summary below should help
readers understand the differences among these working areas:
1. C1.18/C2/C6 deals with solutions for coping with limits for very high penetrations of renewable energy
solutions.
2. C1.20 focuses on how to accommodate high load growth and urban development in future plans.
3. C1.27 looks at the definition of reliability in light of new developments in various devices and services that offer
customers and system operators new levels of flexibility. The focus is on how new developments should change
the definition of reliability and adequacy used with generation and transmission planning. The WG suggested
necessary changes to the definitions of reliability and adequacy.
4. JWG C1.29 looks at the requirement for a change in the conventional planning criteria for future transmission
networks as a result of an increased level of distributed energy resources at MV and LV levels. The WG also

10
assessed the adequacy of currently adopted, and/or those in the process of being of delivered, transmission
planning-methods.
5. C1.30 addresses technical risks and solutions from periodic, large surpluses or deficits of available renewable
generation in a particular area. The working group defined a so called risk-solution matrix to find and illustrate
the total situation of risks and solutions which appears in utilities today.
6. C1.32 examines the demand and energy forecasting techniques currently being employed by power systems
around the world.

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METHODOLOGY
The Working Group (WG) used the following methodology:
 Developed a questionnaire to address the brief of the working group;
 Surveyed Transmission System Operators across the world;
 Working group sessions to review and follow-up on responses;
 Collation of the information; and
 Consolidation and review of results.
QUESTIONNAIRE
A Questionnaire was drafted to obtain the information required to fulfil the Terms of Reference of the Working Group
which are included in Annex 1. The Questionnaire sought the following information:
 Electricity industry structure;
 Background utility information about generation, demand and transmission infrastructure;
 The size, scope and basis for the decision on the most recent 10 major projects; and
 Role of planning criteria in capital investments.
The Questionnaire was designed to facilitate the comparison of data, insofar as it is possible given the broad range
of local factors impacting on the investment decision. Information was sought on the most recent ten major projects.
The Working Group believed this was a reasonable number to provide information for analysis and should be
manageable for the responding party. The Questionnaire Template can be found in Annex 2.
The Questionnaire was sent to contacts in 42 countries.
COLLATION OF INFORMATION
The information received was compiled in a model that enabled analysis to address the questions in the Terms of
Reference. It was formulated in a modular fashion which enabled any additional Questionnaires received to be
incorporated.
INTERPRETATION OF INFORMATION
Interpretation of Categories of Data:
The Questionnaire provided definitions for each of the fields in the Questionnaire Template. These can be found in
Annex 2. The Working Group did not change the categories used by the respondents.

12
Confidentiality:
Information about project cost and need can evolve over the lifetime of project evolution. Some of the respondents
expressed concern that the publishing of information at a point in time could have negative consequences if used in
an incorrect context.
To respect these concerns and maintain confidentiality of information provided, the analysis is presented on a collated
basis. Summarised data of individual responses on an anonymous basis is provided in Annex 5. The draft report
was sent to respondents to confirm that the approach used in the Technical Brochure addressed their concerns.
Statistical Relevance:
The assessment is based on relatively small data sets and therefore seeks only to present the information provided
as commentary regarding practices and trends.
Time:
A common point in time was defined to be the calendar year of 2012. If 2012 data was not available, the most
recent information was then taken and a note regarding data comparability made. Transmission Projects are major
investment decisions involving considerable analysis over many years and don’t change rapidly.
Currency:
All currencies were converted to a single currency representation in Euro with the conversion rates taken from the
European Central Bank as at 31 December 2012.
Normalisation of data:
In order to facilitate the comparison of data which were characterised by different sample sizes, the data was
normalised using their relevant sample sizes. In such a way, the data sets could then be compared and contrasted.
For example, Figure 11 analyses the number of projects per project type on a system operator basis, normalised
using the sample size of projects for each system operator.
Where respondents provided information on more than ten projects, the top ten projects, based on size and
importance, were used in the analysis. There was one exception to this where by reducing the number to ten would
have lost very significant projects and a higher number was used. Some respondents provided less than 10 projects.

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ANALYSIS
The analysis of the information provided has been carried out under the following headings:
 Responses Received
 Investment Drivers for Projects
 Role of the Technical Planning Criteria
 Future expectations
RESPONSES RECEIVED
A total of 24 responses were received from 22 countries and are highlighted in the map in Figure 1 below:
Figure 1: Responding Countries
Figure 2 shows the responses grouped on a regional geographic basis. The pie chart in Figure 3 shows the % of the
responses received per region. Almost half of the responses received were from Europe.
Responding Country
LEGEND

14
Figure 2: Regional Grouping of Responses
Figure 3: Percentage of Responses per Region
Electricity industry structure and Ownership model
The Working Group was interested in whether the electricity industry structure or ownership model influenced the
investment decisions. The electricity industry structure in the responses is shown by region in Figure 4. The
LEGEND
Africa / Middle East
Americas – North
Americas – South
Asia – Pacific
Europe
Responding Country
Africa / Middle
East
13%
Americas –
North
8%
Americas –
South
4%
Asia-Pacific
29%
Europe
46%

15
definitions of electricity industry structure are those used in the Questionnaire and can be found in Section 1 of
Annex 2.
Four categories of industry structure were used. Three of these were different levels of unbundling within the
industry and the fourth was a vertically integrated utility.
Figure 4: Industry Structure per Region
From this can be seen that for the majority of responses (84%) were from an unbundled environment. One sixth of
the responses were from a vertically integrated utility environment. In Europe and the Asia – Pacific Region the
majority of responses were from an unbundled environment with full competition.
Annex 3 contains a table of the Questionnaire responses showing system operator ownership and asset ownership
detail. Figure 5 below shows the number of responses by region on the basis of system operator ownership. “State”
is taken to mean state ownership or state control; and “non-state” is taken to be private or publically listed. For the
purposes of this analysis, if there was multiple ownership, then the controlling share determined the categorisation.
The system operator is in state ownership in the majority of the responses. For the purposes of the analysis, the SO
ownership was also taken as the proxy for the investment decision-maker1. In 75% of the responses, ownership
was state ownership with 25% in non-state ownership.
1 For Brazil the ISO is “non-state” owned, but the decision-maker is the EPE (i.e. the Energy Planning Authority) under the Ministry of Mines and
Energy. Therefore, for this case, the Brazilian ISO is shown as “state”.
Africa /
Middle East
Americas -
North
Americas -
South
Asia - Pacific Europe
Unbundled, full competition 0 1 0 4 9
Unbundled, limited competition 0 0 1 1 1
Unbundled generation 1 0 0 1 1
Vertically integrated 2 1 0 1 0
0
2
4
6
8
10
12
NumberofResponses

16
Figure 5: Responses Categorised by System Operator Ownership
Figure 6 shows the responses per region on a transmission asset ownership basis. Distinction is made between
vertically integrated utilities; Independent System Operators (i.e. no grid ownership) and Transmission System
Operators (i.e. grid ownership). In the majority of cases the system operator owns the assets either as a TSO or a
Vertically Integrated Utility. In 5 (21%) of the responses there was an ISO with no grid ownership.
Figure 6: Responses Categorised by Transmission Asset Ownership
State Non-State
Europe 8 3
Asia-Pacific 6 1
Americas – South 1 0
Americas – North 1 1
Africa / Middle East 2 1
0
2
4
6
8
10
12
14
16
18
20
NumberofRespondents
Integrated
Utility
ISO TSO
Europe 0 1 10
Asia-Pacific 2 3 2
Americas – South 0 1 0
Americas – North 1 0 1
Africa / Middle East 3 0 0
0
2
4
6
8
10
12
14
NumberofResponses

17
Size of system
Another interesting question is whether the size of the system is relevant to the investment decisions. The
classification used is small (i.e. maximum demand less than 10,000MW); medium (i.e. maximum demand between
10,000MW and 40,000MW); and large (i.e. maximum demand greater than 40,000MW). The results are shown in
Table 1, which shows that there was an approximately equal number of responses from small, medium and large
systems.
SMALL
Max. Demand
<10GW
MEDIUM
Max. Demand
10GW - 40GW
LARGE
Max. Demand
>40GW
Africa / Middle East 1 2 0
Americas – North 0 2 0
Americas – South 0 0 1
Asia-Pacific 2 3 2
Europe 4 3 4
TOTAL 7 10 7
Table 1: Size of Utilities Based on Maximum Demand
The maximum demand and transmission network composition (by km) of the responding system operators was
provided for a common point in time and are summarised in Table 2. The data provided by the responding system
operators is summarised per region and therefore represents the responding countries only.
Units
Africa /
Middle
East
Americas –
North
Americas –
South
Asia-
Pacific
Europe
Maximum Demand MW 50,229 46,880 75,000 859,021 332,693
HVAC OHL km 33,390 101,719 99,625 632,629 259,579
HVAC UGC km 140 154 15 566 8,548
HVAC Submarine Cable km 13 - - 59 474
HVAC TOTAL km 33,543 101,873 99,640 633,254 268,601
HVDC Submarine Cable km - - - 80 -
HVDC OHL km - - 1,612 600 -
HVDC TOTAL km - - 1,612 680 -
Network TOTAL km 33,543 101,873 99,640 633,934 268,601
Table 2: Summary of Transmission Network Statistics of Utility by Region (For Responding Countries
Only)

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Expansion,
New Build
86%
Refurbish
7%
Other
7%
INVESTMENT DRIVERS FOR PROJECTS
One of the key elements of the terms of reference is to analyse the data and establish the main reasons for
investment. In this section the data received was analysed using the following factors:
 High level rationale for projects;
 Impact of external factors on decision making;
 Region;
 System operator ownership;
 Asset owner model;
 System size;
 Project size based on cost;
 System operator ownership versus spend;
 Asset owner model versus spend;
 Size versus spend; and
 Use of overhead and underground solutions.
The analysis is based on information provided for 200 projects.
High Level Rationale for Projects
The Questionnaire asked respondents to provide information about the rationale for projects. At the most aggregated
level, categories were “Expansion, New Build”, “Refurbishment”, and “Other”. The category “Other” was used where
a strategic or political reason was the driver for the project. The high level drivers for the projects are summarised
in Figure 7.
Figure 7: High Level Primary Project Categories

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As can be seen from Figure 7 above, the majority of projects (86%) were required for expansion and new build. 7%
of projects were refurbishments with 7% identified as being required for strategic or political reasons.
Figure 8 provides more detail behind the expansion, new build projects, showing the rationale for them. Many of
the projects (i.e. 69% of the projects) evaluated had multiple drivers and hence the sum total of the percentages
exceeds 100%.
Figure 8: Summary of Expansion, New Build Projects by Category, as Percentage of Total
Security of supply is a driver for 69% of the “Expansion, New Build” projects. New connections, either new load or
new generation, and their associated reinforcements are cited as a driver for 42% of the “Expansion, New Build”
projects evaluated. Projects associated with market access account for 14% of the “Expansion, New Build” projects
considered.
Figure 9 provides a breakdown of the reasons behind the refurbishment projects. The predominant driver is like-
for-like asset replacement, accounting for 50% of refurbishment projects. Statutory health and safety requirements
accounts for 14% of refurbishment projects.
0%
10%
20%
30%
40%
50%
60%
70%
80%
Security of Supply New Connection Generation Integration Economic Market Access Loop Flows Mitigation
%ofExpansion/NewBuildProjects

20
Figure 9: Refurbishment Projects by Category, as Percentage of Total
Asset upgrades is also cited as a reason for undertaking refurbishment projects, accounting for 36% of the
refurbishment projects evaluated.
Projects identified as other were quite specific and included a Lighting project to meet Health & Safety Standards
(RSA), projects resulting from a Decision on Nuclear Generation (UK) and Interconnection to Corsica (IT).
Impact of External Factors on Decision Making
Table 3 below shows the categories of projects driven by Expansion, New Build and Refurbishment and the % of
cases where external factors were taken into account. The % is based on the total of projects per project category
where the external factor impacted the investment decision. It should be noted that the majority of projects had
multiple drivers and are captured under multiple project categories.
The following observations can be made:
 Investing on a long-term strategic basis is a factor across all the Expansion and New Build investment
categories. Very few projects are driven by a minimum incremental approach to investment;
 Statutory planning processes are a significant consideration on the reinforcement option for all project
categories;
 Financial considerations are assessed to have a very low influence on the investment option for all project
categories;
 Novel or unconventional transmission technologies is most relevant for projects associated with market
access; and
 Equipment obsolescence is seen as a relevant factor for refurbishment projects only.
0%
10%
20%
30%
40%
50%
60%
Statutory Health & Safety Asset Replacement Asset Upgrade
%ofRefurbishmentProjects

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Project Category
Environmental &
Societal
Technical
Financial
Strategic / General
Approach
SiteorRouteAccess/
Space
LocalOpposition/
Concerns
StatutoryPlanning
Processes
Novel/
Unconventional
TransmissionTech.
Equipment/Tech.
Obsolescence
MinimumIncremental
Approach
LongTermIntegrated
StrategicBasis
RenewableEnergy
Related-StatePolicy
Security of Supply 46% 59% 56% 15% 8% 12% 7% 76% 20%
New Connection 50% 68% 58% 18% 5% 14% 7% 65% 40%
Generation Integration 35% 72% 62% 21% 4% 10% 7% 58% 55%
Economic 31% 47% 63% 22% 8% 15% 8% 80% 19%
Market Access 37% 37% 59% 41% 4% 15% 7% 81% 41%
Loop Flows 44% 50% 72% 8% 8% 0% 3% 81% 28%
Refurbishment 36% 57% 64% 21% 50% 7% 14% 36% 14%
Table 3: Summary of Percentage of Projects per Category Impacted by External Factors

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Region
Table 4 analyses the impact of external factors (e.g. environmental, market change) on the investment decision on
a regional basis.
Region
Total
Number of
Project Per
Region
Environmental &
Societal
Technical
Financial
Strategic / General
Approach
SiteorRouteAccess
/Space
LocalOpposition/
Concerns
StatutoryPlanning
Processes
Novel/
Unconventional
TransmissionTech.
Equipment/Tech.
Obsolescence
MinimumIncremental
Approach
LongTerm
IntegratedStrategic
Basis
RenewableEnergy
Related-StatePolicy
Africa / Middle
East
30 23 21 11 4 4 11 0 20 5
Americas - North 17 4 4 9 1 1 0 0 14 2
Americas - South 10 1 0 2 1 0 1 4 3 3
Asia - Pacific 36 17 16 24 3 5 1 2 33 3
Europe 107 36 74 61 24 5 7 9 64 38
TOTAL 200 81 115 107 33 15 20 15 134 51
Table 4: Summary of Number of Projects per Region Impacted by External Factors
 A long-term strategic basis is a factor in 134 out of 200 investment decisions. This is especially true for the
Asia-Pacific region (i.e. 33 out of 36 projects);
 With the exception of the Americas, site access; local opposition; and statutory planning processes are
factors frequently having an impact on the reinforcement option; and
 Financial factors play a significant role in the investment decision in Africa and the Middle East (i.e. 11 out
of 30 projects) but is not a significant factor in the other regions.
System Operator Ownership
The relationship between the number of projects per project type and whether the System Operator is state or non-
state owned is given in Figure 10 below. The same information is provided in Figure 11, normalised on the number
of projects per category. Based on the responses received 138 projects were from State owned system operators
and 62 projects were from Non-state owned system operators.

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Figure 10: Number of Projects per Project Type, Categorised by System Operator Ownership
Figure 11: Number of Projects per Project Type, Categorised by System Operator Ownership,
Normalised by Number of Projects per Category
State Non-state
Security of Supply 95 43
New Connection (Load or Generator) 51 33
Generator Integration 46 25
Economic 44 15
Market Access 16 11
Loop Flow 30 6
Refurbish 9 5
Other 11 2
Multiple Drivers 96 42
-
20
40
60
80
100
120
No.OfProjects
State Non-state
Security of Supply 69% 69%
New Connection (Load or Generator) 37% 53%
Generator Integration 33% 40%
Economic 32% 24%
Market Access 12% 18%
Loop Flow 22% 10%
Refurbish 7% 8%
Other 8% 3%
Multiple Drivers 70% 68%
0%
10%
20%
30%
40%
50%
60%
70%
80%
Normalised
(%ofProjectsperCategory)

24
 The percentage of projects with multiple drivers is high – 70% for State owned and 68% for Non-state
owned;
 Security of Supply is a significant driver whether the System Operator is State owned or not;
 New connections and generator integration appear to be more significant drivers of projects for Non-state
owned entities with new connections being almost double;
 Loop-flow driven projects are twice the level for State owned system operators; and
 Refurbishment requirements are drivers of a similar percentage of projects, irrespective of ownership.
Asset Owner Model
The relationship between the numbers of projects per project type, categorised by Transmission Asset Ownership is
given in Figure 12 below. The same information is provided in Figure 13, normalised on the number of projects per
category. The number of projects for Integrated Utilities, ISO and TSO are 43, 30 and 127 respectively.
Figure 12: Number of Projects per Project Type, Categorised by Transmission Asset Ownership
Integrated Utility ISO (No Asset Ownership) TSO (Asset Ownership)
Security of Supply 37 24 77
New Connection (Load or Generator) 25 22 37
Generator Integration 6 16 49
Economic 6 10 43
Market Access 1 1 25
Loop Flow - 8 28
Refurbish 3 3 8
Other 1 - 12
Multiple Drivers 28 32 78
-
10
20
30
40
50
60
70
80
90
No.OfProjects

25
Figure 13: Number of Projects per Project Type, Categorised by Transmission Asset Ownership,
Normalised by Number of Projects per Category
 Security of Supply was the most significant driver for projects in Integrated Utilities – 86% of projects. It
was also a significant driver for ISO and TSO projects although at a lesser level – 60%, 66% respectively;
 All three categories of utility had projects with multiple drivers with this being highest for ISOs – 80% of
projects;
 New Connection Projects are more significant for Integrated Utilities and ISOs at 58% and 55% respectively;
and
 For ISOs and TSOs, there were more projects relating to economic and loop flow projects than for integrated
utilities.
System Size
The relationship between the numbers of projects per project type, categorised by system size is given in Figure 14
below. The same information is provided in Figure 15, normalised on the number of projects per category. The
number of projects for small, medium and large systems is 54, 76 and 70 respectively.
Integrated Utility ISO (No Asset Ownership) TSO (Asset Ownership)
Security of Supply 86% 60% 66%
New Connection (Load or Generator) 58% 55% 32%
Generator Integration 14% 40% 42%
Economic 14% 25% 37%
Market Access 2% 3% 21%
Loop Flow 0% 20% 24%
Refurbish 7% 8% 7%
Other 2% 0% 10%
Multiple Drivers 65% 80% 67%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Normalised

26
Figure 14: Summary of Number of Projects per Project Type, Categorised by System Size
Small (<10GW) Medium (10GW - 40GW) Large (>40GW)
Security of Supply 39 60 39
New Connection (Load or Generator) 27 20 37
Generator Integration 19 15 37
Economic 15 24 20
Market Access 7 9 11
Loop Flow 17 7 12
Refurbish 3 7 4
Other 8 2 3
Multiple Drivers 39 44 55
-
10
20
30
40
50
60
70
No.OfProjects

27
Figure 15: Summary of Number of Projects per Project Type, Categorised by System Size, Normalised
by Number of Projects per Category
 Security of Supply is the most significant driver for projects for all system sizes. It is higher for small and
medium size systems than large;
 Projects with multiple drivers were > 70% for small and large systems;
 A similar % of projects were driven by economic reasons, regardless of system size;
 There was a higher % of loop flow projects for small and large systems;
 Projects driven by new connections were highest for small and large size systems; and
 The % of projects driven by refurbishment was consistent between small and large systems at 6%. For
medium systems refurbishment driven projects were higher at 9%.
Project Size Based on Cost
Cost information was provided for 135 of the 200 projects. In many of the cases where costs were not provided,
the commercial sensitivity of the values was cited as the reason. For the projects where capital cost estimates were
Small (<10GW)
Medium (10GW -
40GW)
Large (>40GW)
Security of Supply 72% 79% 56%
New Connection (Load or Generator) 50% 26% 53%
Generator Integration 35% 20% 53%
Economic 28% 32% 29%
Market Access 13% 12% 16%
Loop Flow 31% 9% 17%
Refurbish 6% 9% 6%
Other 15% 3% 4%
Multiple Drivers 72% 58% 79%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
Normalised

28
provided, costs were summarised by numbers of projects falling within specific capital cost ranges, as illustrated in
Figure 16 below.
Figure 16: Summary of Capital Cost of Projects
From the above Figure, it can be seen that:
 The highest volume of projects is in the range of €0 million to €50 million; and
 There are a significant number of projects that cost in excess of €500 million being undertaken.
System Operator Ownership Versus Spend
SO Ownership
Capital Budget
(€'m)
Total No.
Projects
Average Spend
per Project
(€'m)
State 24,623 106 232.30
Non-state 6,710 29 231.37
Total 31,333 135 232.10
Table 5: Summary of Capital Budget by System Operator Ownership
0
10
20
30
40
50
60
70
€0m-€50m €50m-€150m €150m-€500m >€500m
NumberofProjects
Project Capital Cost

29
Table 5 shows that the average capital spend per project is approximately the same regardless of System Operator
ownership at an average of €230m per project.
Asset Owner Model Versus Spend
Asset Ownership
Capital
Budget
(€'m)
Total No.
Projects
Average
Spend per
Project
(€'m)
Integrated Utility 3,828 30 127.61
ISO (No Asset Ownership) 9,181 25 367.25
TSO (Asset Ownership) 18,324 80 229.05
Total 31,334 135 232.10
Table 6: Summary of Capital Budget by Asset Ownership
Table 6 shows that the average spend per project is highest for ISOs at €367m and lowest for Integrated Utilities at
€128m.
These results are somewhat affected by the number of respondents per classification with 3, 4 and 11 for Integrated
Utility, ISO and TSO respectively.
Size Versus Spend
Utility Size
Total
Maximum
Demand per
Category
(MW)
Total Capital
Budget per
Category
(€'m)
Total
No.
Projects
per
Category
Average
Spend
per
Project
(€'m)
Average
Spend
per MW
(€'m)
Small (<10GW) 34,613 4,138 54 76.63 0.120
Medium (10GW - 40GW) 195,821 12,328 53 232.61 0.063
Large (>40GW) 1,133,389 14,867 28 530.95 0.013
TOTAL 1,363,823 31,333 135 232.10 0.023
Table 7: Capital Budget Versus Utility Size (represented by maximum demand)
The figures given in Table 7 above indicate that the smaller utilities are spending less per project than the larger
utilities. However, the inverse is true when measuring the average spend per demand MW.

30
Use of Overhead and Underground Solutions
The projects submitted are described for the majority as overhead line solutions. The responses received indicated
the use of underground cables is primarily for when overhead lines were not possible, with the greatest application
in urban areas.
ROLE OF THE TECHNICAL PLANNING CRITERIA
One of the main objectives of the Terms of Reference was to establish the role of Technical Planning Criteria (TPC)
in investment decisions. Section 4 of the Questionnaire elicited the information for this aspect of the analysis. The
definitions in the next two paragraphs were used where Technical Planning Criteria were taken as a subset of the
Transmission Planning Criteria.
Technical Planning Criteria is taken to mean the collection of technical criteria and performance parameters (e.g.
reliability, voltage etc.) necessary for the design and planning of the transmission system;
Transmission Planning Criteria is taken to mean the collection of all necessary criteria, including the Technical
Planning Criteria, Economic Evaluation Criteria and Methodology, Project Prioritisation Methods etc. that form part
of the capital investment process.
Use of Technical Planning Criteria
Compliance with Technical Planning Criteria is the primary determinant of reinforcement need according to each of
the respondents (excluding those for which no comment was received). Investments to meet minimum redundancy,
quality of supply and stability standards are assessed using deterministic methods.
Compliance with the Technical Planning Criteria also determines the timing of reinforcements.
The responses are shown in Figure 19 below:
Figure 17: Role of Technical Criteria in Determining Project Need by Number of Responses
statutory obligations are met; and economic investments refer to those that reduce overall costs and are not required
0 5 10 15 20 25
No Comment
Determinant of Minimum Performance /
Redundancy

31
to meet licence or statutory obligations. The Technical Planning Criteria were the primary determinant of
reinforcement need for all cases except those considered to be economic in nature.
Figure 18: Summary of Role of the Technical Planning Criteria in Circuit Technology Selection by
Number of Responses
Based on the feedback from the majority of respondents, as shown in Figure 18, the choice of overhead line (OHL)
or underground cable (UGC) is not directly addressed in the Transmission Planning Criteria. According to
respondents, the use of UGC is primarily used to mitigate constraints or at lower voltages, with the primary
technology choice being in favour of OHL technologies.
Use of Probabilistic Criteria
One respondent indicated that a full probabilistic methodology was employed. The majority of respondents indicated
that deterministic methods were used to evaluate the need for reinforcement with a significant number indicating
that both methods were made use of, depending on the situation. Probabilistic methods to varying degrees are
made use of to supplement deterministic methods by several TSOs. The results are summarised in the Figure 19
below:
Figure 19: Summary of Use of Deterministic and Probabilistic Methods by Number of Responses
0 2 4 6 8 10 12
No Comment
Not Addressed by TPC
Primarily OHL; UGC for Mitigation
Routinely for Lower Voltage Levels
0 2 4 6 8 10 12 14
No Comment
Both
Probabilistic
Deterministic

32
Use of Economic Principles
Based on the feedback of respondents, economic principles are considered by the SOs. Economic principles are
primarily used by the SOs to do the following:
 Justify a reinforcement / capital investment;
 Identify the least cost reinforcement option; and
 Prioritise projects.
A summary of responses received is shown in Figure 20 below. The majority of respondents (i.e. 19/24) indicated
that Expected Unserved Energy(EUE) or Cost of Unserved Energy (COUE) are considered in their Transmission
Planning Criteria.
Figure 20: Summary of Economic Considerations
Changes to the Transmission Planning Criteria
Regarding recent changes or modifications made to the Transmission Planning Criteria, 12/24 respondents claiming
that changes had been made to the Transmission Planning Criteria.
The changes that were made were aimed at:
 Reflecting the changing industry (e.g. the integration of high levels of generation from Renewable Energy
Sources (i.e. RES));
 Accommodating technical changes e.g. Dynamic Line Rating (DLR) or Special Protection Schemes (SPS),
etc.; or
 Accommodating industry-wide practices (e.g. economic assessment methodology).
0 5 10 15 20
No Comment
EUE, COUE Considered
Not Considered

33
0 2 4 6 8 10
Insufficient Data
No.>=20
10>=No.<20
No.<10
Figure 21: Summary of Recent Changes to TPC by Number of Responses
FUTURE EXPECTATIONS
Industry Structure
Of the respondents who provided feedback, 71% don’t envisage change in industry structure and 18% are uncertain
that any changes are likely to arise. 12% expect changes. The changes identified relate to changes to vertically
integrated utilities to: (1) allow the formation of an independent ISO as a means of facilitating Independent Power
Producers; and (2) the promotion of renewable generation sources and the potential for localised independent power
systems to be formed.
Future Investments
Responses indicate that there are in excess of 10 projects identified per respondent that are already in the pipeline.
For 9 of the 24 respondents, in excess of 20 projects are in the pipeline.
Figure 22: Summary of Number of Projects in the Pipeline but not yet Approved
0 2 4 6 8 10 12
No Comment
No Change
Other Modification
Minimal Administrative Modification
Modification Regarding Probabilistic
Approach
Economic Evaluation Related
Modification
New Technology Related (e.g. SMART)
RES-Related Modification

34
Of the respondents that provided data regarding their expected future capital expenditure, the majority (i.e. 8/14)
estimate that their total capital expenditure for the next 10 years is in excess of € 1 billion. The results are shown
in Figure 23 below.
Figure 23: Summary of Expected Future Capital Investment (10 years) by Number of Responses
Figure 24 shows the types of future projects and the number of respondents expecting to invest in these. The
majority of future developments are expected to relate to new HVAC overhead lines and new HV substations.
Figure 24: Summary of Types of Future Projects by Number of Responses
0 1 2 3 4 5 6
No. > € 5b
€ 1.0b > No. =< € 5b
€ 0.5b > No .=< € 1.0b
No. <= € 0.5bn
0 2 4 6 8 10 12 14 16
Interconnection
Other Assets
Asset Replacement
New HV Stations
New Cables
New Overhead Lines

35
The main drivers for these future projects are identified as security of supply. Market access and new connections
are also key project drivers. The results are summarised in Figure 25 below.
Figure 25: Summary of Drivers of Future Projects by Number of Responses
0 5 10 15
Other
Refurbishment
Market Access (Interconnection)
Economic: Constraints Cost Reduction
/ Net Market Benefits / Optimisation
System Reinforcement for Generation
Integration
RES Integration
New Connection (Load or Generator)
Security/ Reliability/ Quality of
Supply

36

37
CONCLUSION
A review of the main drivers of investment decisions in bulk power transmission infrastructure made by utilities (state
or privately owned) around the world was undertaken using responses to a detailed questionnaire. The responses
received were collated and the results presented, broken down by region and investment decision driver.
In total, 24 responses were received. Statistically, that provides a general overview of approaches to investment
decisions around the world, which can be used as a peer reviewed benchmark for individual utilities to compare their
approach to investment decisions against average global practice.
For purposes of confidentiality, information is aggregated or presented anonymously.
MAIN REASONS FOR INVESTMENT
The majority of investments are for expansion and new build.
The majority of capital projects undertaken in responding countries (i.e. 86% of the list of projects compiled) involved
the expansion of the transmission network with the construction of new infrastructure. The main reason given is to
ensure transmission network security of supply (69%); followed by reinforcements required to facilitate the
connection of new generator and demand customers; reinforcements necessary for the integration of generation;
and economically motivated investments. Security of Supply is a significant driver irrespective of the System Operator
or asset ownership model.
Capital projects required to refurbish or upgrade the existing transmission network accounted for 14% of the projects
undertaken by responding countries. The main drivers of refurbishment projects were the replacement of assets at
the end of their useful life (50%) and the upgrade of assets (36%).
For many of the projects evaluated as part of this review (i.e. 69%), multiple justifications for the investment were
given.
Transmission Investments are Long-Term and Strategic
Investing on a long-term strategic basis is a factor (i.e. 134 out of 200 investment decisions) across all the investment
categories. This is especially true for the Asia-Pacific region (i.e. 33 out of 36 projects).
Very few projects (i.e. 15 out of 200) are driven by a minimum incremental approach to investment.
Statutory Planning Impacts the Selection of Reinforcement Option
Consideration of statutory planning processes has a significant impact on the reinforcement option for all project
categories. With the exception of the Americas, site access; local opposition; and statutory planning processes are
factors frequently having an impact on the reinforcement option.
Novel Technologies have a Low Impact on Investment Options
The use of novel or unconventional transmission technologies is most relevant for projects associated with market
access.
For refurbishment projects, 50% of projects identify technology or equipment obsolescence as a factor impacting
the identification of the reinforcement option.
Financial Considerations Impacting Investment Options is a Regional Factor

38
Generally, financial factors play a small role in the investment decision (i.e. 20 out of 200 projects). However, this
is not the case across all regions: For Africa and the Middle East, financial factors play a significant role in the
investment decision (i.e. 37%).
THE ROLE OF THE TECHNICAL PLANNING CRITERIA
The Technical Planning Criteria are the Determinant of Minimum Performance / Redundancy
Compliance with Technical Planning Criteria is cited as the primary determinant of reinforcement need by
respondents. Compliance with the Technical Planning Criteria also determines the timing of reinforcements.
statutory obligations are met; and economic investments refer to those that reduce overall costs and are not required
to meet licence or statutory obligations. The Technical Planning Criteria were the primary determinant of
reinforcement need for all cases except those considered to be economic in nature.
The choice of overhead line (OHL) or underground cable (UGC) is not directly addressed in the Transmission Planning
Criteria. According to respondents, the use of UGC is primarily used to mitigate constraints or at lower voltages,
with the primary technology choice being in favour of OHL technologies.
Economic principles (such as cost of unserved energy, societal impacts etc.) are considered in most Transmission
Planning Criteria.
Investments are Driven Predominantly by Deterministic Criteria
Respondents differentiated between deterministic and probabilistic assessment methods: Investments to meet
minimum redundancy, quality of supply and stability standards are assessed using deterministic methods.
Probabilistic methods to varying degrees are made use of to supplement deterministic methods by several TSOs.
The majority of respondents indicated that deterministic methods were used to evaluate the need for reinforcement
with a significant number indicating that both methods were made use of, depending on the situation.
FUTURE EXPECTATIONS
Future Investments are expected
Respondents gave an indication of a pipeline of future projects. The majority of future developments are expected
to relate to new HVAC overhead lines and new HV stations. The main driver of future reinforcement is security of
supply.
SUGGESTED FUTURE WORK
The results of the review identify several areas that could benefit from further investigation. These are described
below:
Changes to Transmission System Planning Criteria
Several respondents indicated that their system planning criteria has been modified or is expected to be modified
shortly in order to account for the impact of new generation technology and, for some, the use of probabilistic
planning criteria.
Further work that seeks to draw out which system planning criteria have changed due to new generation technology
and use of probabilistic criteria would be a suggestion for future work.

39
The Role of Future Demand Growth
Demand is expected to reduce with the emphasis on efficiency and the installation of embedded renewable
generation sources. Further work is suggested to investigate the implications of these changes for investment
decisions.
The Role of Power System Size
The geographical dispersion and size of demand appear to be related to the types of projects undertaken and the
types of investments made. Further work to investigate the relationship between the type of project relevant to
system size is therefore suggested.
Cost Benefit Analysis
There appears to be a growing role of social impact assessment and the accommodation of social impacts on both
the cost of the investment and the investment decision itself. Work to investigate the range of quantifiable and
unquantifiable costs and benefits, including the techniques made use of, would be of significant use.
In fact, in the years since the survey was taken, work on cost benefit analysis for transmission investments has
progressed. While reasons for this were not included in the survey, they could include the need to involve
stakeholders and affected citizens in the planning process in better organised ways, e.g. in Europe in many countries
and also due to the EU Infrastructure Regulation of 2013. Such reasons for progress on CBA could also be due to
the recent strong global consensus to take action against climate change, including strong investments in renewable
energy worldwide: The fluctuating characteristics of the electricity generation especially from the renewable energy
technologies with the largest recent cost decreases, incl. solar PV, onshore and offshore wind, will lead at high
penetration levels to temporary regional surpluses and deficits of renewable energy. Strengthened continental-scale
transmission networks can provide a relatively low-cost way to use surpluses (in another region with less generation
at the time of a regional surplus) or to cover deficits (from another region with more generation at the time of a
regional deficit). This mixture of economic and security of supply benefits can best be analysed in a cost-benefit
format, and the above-mentioned stakeholder involvement leads to inclusion in the CBA of other, less quantifiable
criteria. As one of many global examples of increasing and more sophisticated use of CBA, see ENTSOG and ENTSO-
E, ENTSOs consistent and interlinked electricity and gas model, 21 Dec. 2016.
The Role of Strategic Investments in Buying an Option to Offset Future Uncertainty
The assessment of the value of long-term strategic investments in contrast with short-term incremental investments
is not fully recognised when evaluating the impact of future uncertainty, potentially impacting on investment
decisions. Further work to investigate the role of strategic investments in buying an option to offset future
uncertainty is suggested.
The Impact of Micro Grids on Future Investment in Main Transmission Grid
An increase in micro grids and their impact on power flow and main transmission grid utilisation is likely to impact
on the business case for grid development. Grid connected micro grids add flexibility for the user and greater
volatility in operations for the TSO. Therefore they introduce additional risk to any investments in the main
transmission system potentially impacting on the business models used by TSOs for their network development.
Further work to investigate the impact of micro grids on future investment in the main transmission system is
therefore suggested.

40

41
ACKNOWLEDGEMENTS
The contributions made by a number of people who made their time and expertise available are acknowledged with
thanks.
The contributions and commitment of the Working Group are acknowledged and the people who supplemented this
work at the meetings that were held.
A particular acknowledgement is made of those people who filled in the questionnaire and provided the data. They
are listed as follows:
M. Avila Rosales (MX), D. Bones (AU), D. Elmakis (IL), R. Estment (ZA), D. Carvalho (BR), A. Croes (NL), C. Dalal (DK),
M. de Fatima Gama (BR), L. Fisher (IE), A. Ilyenko (RU), L. Juan (CN), D. Iorio (IT), E. Montiel (AU), L. Oroszki (HU),
J. Palermo (US), C. Roe (US), C. Schorn (DE), and D. Zhongming (CN).
The support of the Study Committee C1 and the Co-ordinators of the Working Groups is also acknowledged.

42

43
ANNEX 1: TERMS OF REFERENCE
CIGRE Study Committee N° C1
PROPOSAL FOR CREATION OF A NEW WORKING GROUP *
WG C1.15 Name of Convenor: Adele Sleator
Title of the Group : Review the drivers for transmission investment decisions and the role of technical
planning criteria in transmission investment
Background:
Traditionally investment in transmission infrastructure development has mainly been driven by planning
reliability and security criteria, that set the technical standards to which the network is planned. The network
is operated to operational criteria. The planning criteria and operational standards are usually complementary
if the network is to be designed to meet desired technical operational standards. With de-regulation, evolution
of electricity markets, increase in renewable generation, the drive to combat climate change by mechanisms
including energy efficiency initiatives and micro-generation, the decision making environment in transmission
development investment is changing. Drivers of and factors influencing transmission investment decisions
could include technical criteria, economic criteria, congestion management, facilitating market integration and
relieving market constraints, operational criteria, strategic considerations, environmental aspects, societal
aspects and risk assessment. The drivers could also include political decision making and urbanisation which
lead to undergrounding of existing and new power lines based on aesthetic and health and safety issues.
Investments maybe made based on short-term concerns and a minimal incremental approach or be made on
a long–term more integrated strategic basis. The regulatory environment and ownership of the decision
making company may also influence the approach to investment decision making.
The objective of this working group is to review the rationale used for transmission investment decisions,
establish the role of technical planning criteria in investment decisions and identify trends in investment
drivers.
Deliverables:
 Establish data on recent transmission investment decisions and the regulatory and market environment in
which the decisions were made.
 Analyse data and identify the main reasons for investment.
 Establish the role of technical criteria in investment decisions.
 Publish the results in a Technical Brochure with an Executive Summary in Electra
Starts: April 2009
Final Report: April 2011
Comments from Chairmen of SCs concerned :
Approval by Technical Committee Chairman : Date :

44
ANNEX 2: QUESTIONNAIRE TEMPLATE
CIGRE Study Committee No
C1
WG C1.15
13-Mar-12
adele.sleator@eirgrid.com mario.duarte@eirgrid.com
Convenor: Adèle Sleator
mario.duarte@eirgrid.com
Title of the Group
Contact telephone number:
Please return this completed spreadsheet to:
Review the drivers for transmission investment decisions and the role of
technical planning criteria in transmission investment
If you need any clarification, please contact:
Web address of your organization:
Name of company / organization that you
represent:
Respondent’s Information
Name of Respondent:
Your position/ function within the
organization:
Email address:
Thank you for taking the time to complete this questionaire.
This is the person who has filled in the questionnaire so that we can contact the individual in the event that clarification is needed.
The following sections are to let us know who you are.

45
1-
1.1
1.2
1.3
Transmission asset owner
Transmission system operator
Generator (State owned)
Generator (IPP)
Market administrator
Regulator
Independent Transmission Planner
Other (please specify)
1.4
Transmission asset owner
Transmission system operator
Market administrator
Regulator
Independent Transmission Planner
Other (please specify)
1.5
1.6
These models are represented diagrammatically in the attached Note
Do you expect a change in the industry structure in the next 5 years? Is so, what and why?
ELECTRICITY INDUSTRY STRUCTURE
Please provide some background information relating to the electricity industry within which you work,
by filling out "Section 2: Background Information".
Who is the party that performs the planning of the transmission system?
Please mark the appropriate option with an 'X' (it is possible to select more than one option) :
Unbundled, limited competition
Unbundled, full competition
We define the following generic types of Industry structures, based on the two structural dimensions
of: (1) degree of unbundling; and (2) extent of competition:
a) Model 1: Vertically Integrated:
b) Model 2: Unbundled Generation:
c) Model 3: Unbundled, Limited Competition:
d) Model 4: Unbundled, Full Competition:
Please select the company type that best describes the company for which you work.
Please mark the appropriate option with an 'X' (it is possible to select more than one option) :
In respect of electricity industry restructuring, please select the most appropriate option that would
best describe the restructuring of the electricity industry within which you operate, by linking the before
state to the current state:
Please mark the appropriate 'from' and 'to' options with an 'X'
From To
Unbundled generation
Vertically integrated
How would you best describe the structure of the electricity industry in which you operate?
Please mark the appropriate option with an 'X'
Date restructuring effective from:

46
Notes to assist with completing "Section 1: Industry Structure"
Definitions are referenced to the work done by Cigre Working Group C1.12, "Impact of Transmission/Grid Codes on the Planning of Systems", Draft1.1, August 2010

47
2-
2.1
2.2
Maximum demand for 2011*:
2.3
HVAC Network -
Length of transmission circuits:
As at 31 December 2011*
Voltage
(kV)
Overhead
Line
(km)
Under-
Ground
Cable
(km)
Under-
Water
Cable
(km)
Voltage level 1 =
Voltage level 2 =
Voltage level 3 =
Voltage level 4 =
Total =
Country interconnections:
Number
of circuits
Total
Transfer
Capacity
IMPORT
(MW)
Total
Transfer
Capacity
EXPORT
(MW)
Border 1
Border 2
Border 3
Border 4
Border 5
HVDC Network -
Length of transmission circuits:
Voltage
(kV)
Overhead
Line
(km)
Under-
Ground
Cable
(km)
Under-
Water
Cable
(km)
Voltage level 1 =
Voltage level 2 =
Total =
Country interconnections:
Number
of circuits
Total
Transfer
Capacity
IMPORT
(MW)
Total
Transfer
Capacity
EXPORT
(MW)
Border 1
Border 2
Border 3
Border 4
Border 5
State area for which information in provided:
Background Utility (Country) Information:
Note: * If information is not available for 2011, please provide for the most recent year and state the year.
Renewable generation capacity:
Other Renewable (Biomass, tidal, wave) generation capacity (MW)
Total energy exported for 2011* (GWh):
Generation:
Demand:
Total energy imported for 2011* (GWh):
Transmission Infrastructure:
Installed generation capacity, 31 December 2011* (MW):
Thermal generation capacity (MW):
Nuclear generation capacity (MW):
Wind generation capacity (MW)
Total energy produced for 2011* (GWh):
Installed dispatchable generation capacity, 31 December 2011* (MW):
Hydro generation capacity (MW):

48
3-
3.1
3.2
TRANSMISSION INFRASTRUCTURE INVESTMENTS
We define the following types of investments in transmission infrastructure (refer to notes attached):
a) Expansion or new build: typically related to connecting new generators or customers, or
additional infrastructure build to accommodate organic growth of the network;
b) Sustaining or refurbishment: typically related to ensuring that existing capacity remains available
and is based on the condition of the plant that has reached the end of its useful life;
c) Other, including political drivers: relates to drivers other than expansion or refurbishment and
would include government policy related project drivers
Please provide information regarding the 10 most recent (i.e. last 5 years) transmission projects that
have either been completed or have been approved for expenditure (by utility & regulatory body where
relevant) and are progressing into the statutory planning phase. The information is to be provided by
completing both pages of the blank table (Table 3.1) provided. Selection should be according to
strategic importance and project size/value.
Looking forward over the next 10 years, please provide the following information regarding projects
that are in the pipeline, but are not yet approved:
(a) How many individual projects or schemes are currently planned?
(b) What is the estimated total CAPEX value for the period? Please indicate currency.
(d) What are the main drivers for these future projects?
(c) Indicate , briefly, the type and scope of the projects, e.g. voltage level, technology.

49
TABLE 3.1: PROJECT SUMMARY TABLE
P A G E 1
Security/Reliability/Qualityof
Supply
11
NewConnection(Loador
Generator)
12
SystemReinforcementfor
GenerationIntegration
13
Economic:ConstraintsCost
Reduction/NetMarketBenefits/
Optimisation
14
MarketAccessbetweenPrice
Arease.g.Interconnection
15
NetworkSecurityAddressingLoop
Flows
16
SiteorRouteAccess/Space
21
LocalOpposition/Concerns
22
StatutoryPlanningProcesses
23
Novel&Unconventional
TransmissionTechnology
25
TechnicalObsolesenceof
Equipment/Technology
26
MinimumIncrementalApproach
29
LongTermIntegratedStrategic
Basis
30
RenewableEnergyRelated-State
Policy
31
1
2
3
4
5
6
7
8
9
10
PROJECT DRIVERS9
(Indicate selection with 'X')
FACTORS INFLUENCING DECISION MAKING19
(Indicate selection with 'X')
PROJECT DESCRIPTION
PROJECTSTATUS3
(e.g.Constructed;Approvedand
indesign&Permitingphase;Inconstruction)
Strategic/
General
Approach28
Technical24
TITLE1
BRIEF DESCRIPTION2
IDENTIFIER
Financial27
TIMING
EstimatedTotalCost-[ETC](€'m)4
ProjectDevelopmentTime(months)8
%ofETCAllocatedtoCIRCUITS5
%ofETCAllocatedtoSUBSTATIONS/
TERMINALS6
Commissioning/EstimatedCompletionDate
(mm/yy)7
COST
Environmental
&Societal20
Refurbish17
Other(IncludingPoliticalDrivers)18
Expansion,New
Build10
Other33
General Comment or
Clarification Note32
Number

50
TABLE 3.1: PROJECT SUMMARY TABLE (Cont/...)
P A G E 1 P A G E 2
Technical Planning Criteria35
What non-compliance with the
Technical Planning Criteria is the
project solving / addressing e.g. N-1,
thermal overload, under/over voltage,
transient stability etc.?
Describe the role, if any, of a
business case (cost-benefit analysis)
in justifying the project
Describe the relationship between the
Planning Criteria and the Business
Case (cost-benefit analysis), if any
If relevant, describe the
methods/techniques used in the
business case (cost-benefit analysis)
Other37
1
2
3
4
5
6
7
8
9
10
PROJECT DESCRIPTION
PROJECTSTATUS3
(e.g.Constructed;Approvedand
indesign&Permitingphase;Inconstruction)
TITLE1
BRIEF DESCRIPTION2
IDENTIFIER TIMING
EstimatedTotalCost-[ETC](€'m)4
ProjectDevelopmentTime(months)8
%ofETCAllocatedtoCIRCUITS5
%ofETCAllocatedtoSUBSTATIONS/
TERMINALS6
Commissioning/EstimatedCompletionDate
(mm/yy)7
COST
JUSTIFICATION34
Project Business Case36
Number

51
No. TERM DESCRIPTION
1 TITLE The title by which the project is commonly known within the electricity industry
2 BRIEF DESCRIPTION General description of the project summarising its scope; objective; location within the country; circuit data (OHL vs. UGC, km); substation info (AIS, GIS,
Voltages); FACTS (Type, motivation, location); key statistics; significance of the project (key issues and concerns; status of the project)
3 PROJECT STATUS Status of the project e.g. Constructed, approved and in design & planning phase, in construction
4 Estimated Total Cost (ETC) The estimated cost of the project, typically in nominal currency figures. Figures presented in the currency of the country (e.g. €, $, GBP etc.) and the applicable
date. Costs should include the capital costs of the items of plant, the civil engineering costs, the engineering and project development costs etc.
5 % Allocation - CIRCUIT The % of the ETC (including the allocation of engineering and project development costs) that can be attributed to the building of circuits
6 % Allocation - S/STATION The % of the ETC (including the allocation of engineering and project development costs) that can be attributed to the building of substations or HVDC
terminals
7 Commissioning Date The expected date of completion of all commissioning or the required date of the project
8 Project Development Time The time taken from the date when the company responsible for planning approved proceeding with the project to the date of commissioning. This time would
include the project development, consultation, statutory planning and construction period
9 PROJECT TYPE/DRIVER The fundamental need or motivation for the project - i.e. the reason for the infrastructure investment. Please fill in an 'X' in all of the reasons that apply
10 Expansion, New Build Projects that involve the construction or addition of new transmission assets (i.e. additional circuits, substations)
11 Security/Reliability/Quality of
Supply
Projects related to improving security, reliability and/or quality of supply, where the need is measured as compliance with formal technical planning criteria
12 New Connection (Load or Generator) Projects related to the connection of new generation or new demand customer to the transmission grid
13 System Reinforcement for
Generation Integration
Projects necessary to reinforce the broader transmission system to permit the unconstrained operation of new generation (typically referred to as "deep"
connections)
14 Economic: Constraints Cost
Reduction / Market Benefits
Projects that are motivated on the grounds of economic benefits alone, e.g. reduction in cost of losses, improved market efficiency (reduced congestion or
constraints costs) or improved market access
15 Market Access between Areas Projects that involve the interconnection of power systems, typically between neighbouring utilities or neighbouring electricity markets
16 Network Security Addressing Loop
Flows
Projects that involve network reinforcement to address issues (such as loop flows) arising from increased energy trade; increased inter-area power flow; or
interconnections
17 Refurbishment Projects that involve capital investment in new assets to replace existing assets that are in poor physical condition to restore the original level of performance
18 Other (Including Political Drivers) Any other project drivers that are not addressed by the other categories provided, and which would include political factors
19 FACTORS INFLUENCING DECISIONS Factors that were taken into account or affected the decision making in respect of the project for which information is provided
20 Environmental & Societal Environmental or social issues that impact on the project decision e.g. special areas of conservation, architectural or archeological significance, etc.
21 Site or Route Access / Space The ability to access the chosen route or site, where restrictions relate to physical constraints such as urban development
22 Local Opposition & Concerns The issues raised by local areas that had to be considered in developing the final reinforcement option
23 Statutory Planning Processes Issues relating to the statutory planning processes or the development of Environmental Impact Assessments
24 Technical Technical issues that were a key consideration in the development of the project and which influenced the final solution / option
25 Novel & Unconventional
Transmission Technology.
The role of the availability or applicability of new technologies (e.g. HTLS, RTTR, Superconducting, FACTS & ETO, WAMS etc.) as means of addressing system
constraints in the project decision making
26 Technical Obsolesence Projects that are required in order to accommodate the obsolescence of existing equipment. The solution may not be optimum as a result
27 Financial Financial issues that impact on the choice of option, relating to affordability of financial bankability
28 Strategic / General Approach This relates to strategic issues that shape the nature of the reinforcements made
29 Minimum Incremental Approach An incremental approach on a project-by-project basis where planning is performed on shorter time horizons
30 Long-Term Integrated Strategic
Basis
A long-term planning approach that considers investments / reinforcements in the context of long-term and strategic network development
31 Renewable Energy Related-State
Policy
The investments / projects are related to the integration of renewable energy sources that are supported largely by policy e.g. wind energy

52
32 General Comment or Clarification
Note
Any elaborating comments that relate to the factors mentioned as influencing the project decision making
33 Other Any other factors that influenced decision making that have not been adequately addressed by the list of categories provided - please provide an explanation
34 JUSTIFICATION The reasoning or argument that supports the need for the project.
35 Technical Planning Criteria The technical criteria or standards used to plan and design the transmission system.
36 Project Business Case The supporting cost-benefit analysis used to justify that the project creates additional value and should proceed as defined
37 Other Any other factors that impacted on the business case or justification of the project that was necessary to permit the project to proceed to construction

53
4-
4.1
a.
b.
c,
d.
4.2
4.3
4.4
4.5
4.6
To what extent, and under what conditions, does the Transmission Planning Criteria address the decision to construct
overhead lines versus underground cables?
Do you expect a change in the Transmission Planning Criteria in the next 5 years? If so, what and why?
Are investments driven by deterministic or probabilistic planning approach? Please explain.
Describe the role of the Technical Planning Criteria in establishing the need and identifying/defining the reinforcement
projects required.
To what extent are economic principles (such as cost of unserved energy, societal impacts etc.) addressed or considered
in the Transmission Planning Criteria?
The role of the TPC in justifying capital investment? If yes, please explain.
The application of the TPC in identifying transmission network constraints? If yes, please explain.
The scope and content of the TPC, e.g. to accommodate renewable wind generation; new techniques etc.
ROLE OF PLANNING CRITERIA (TECHNICAL & TRANSMISSION) IN CAPITAL INVESTMENTS
Has there been a change in Technical Planning Criteria (TPC) in the last 5 years in respect of the following?
The general application of the TPC? If yes, please explain.
Technical Planning Criteria is taken to mean the collection of technical criteria and performance parameters (e.g. reliability,
voltage etc.) necessary for the design and planning of the transmission system;
Transmission Planning Criteria is taken to mean the collection of all necessary criteria, including the Technical Planning Criteria,
Economic Evaluation Criteria and Methodology, Project Prioritisation Methods etc. that form part of the capital investment process.

54
ANNEX 3: QUESTIONNAIRE RESPONSES
Region Country
System Operator
Name
Company (SO)
Ownership2
Asset Ownership
1 Africa / Middle East South Africa ESKOM State Integrated Utility
2 Africa / Middle East Israel IEC State Integrated Utility
3 Africa / Middle East Jordan JEPCO Non-State Integrated Utility
4 Americas – North Mexico CFE State Integrated Utility
5 Americas – North
United States of
America
ATC Non-State TSO
6 Americas – South Brazil ONS State3
ISO
7
Asia-Pacific
AUS: Western Aus Western Power State TSO
AUS: Queensland Powerlink State TSO
AUS: Victoria AEMO State ISO
8 Asia-Pacific China
China Southern
Power Grid
Company
State Integrated Utility
9 Asia-Pacific Japan：Kyushu Kyushu Erectric Co Non-State Integrated Utility
10 Asia-Pacific New Zealand Transpower State ISO
11 Asia-Pacific Russia SO UPS State ISO
12 Europe Denmark ENERGIENET State TSO
13 Europe France RTE State TSO
14 Europe Hungary MAVIR State TSO
15 Europe Ireland EIRGRID State ISO
16 Europe Italy TERNA Non-State TSO
17 Europe Montenegro CGES State TSO
18 Europe Netherlands TENNET State TSO
19 Europe Norway STATTNETT State TSO
20 Europe Poland PSE State TSO
21 Europe Spain REE Non-State TSO
22 Europe Great Britain NATIONAL GRID Non-State TSO
Table A3-1: Summary of Responses
2 Company (SO) Ownership is used as a proxy for the investment decision-maker, which is a correct proxy for all SOs analysed with the
exception of Brazil where the SO Ownership is non-state, but the decision-maker is the Ministry of Energy (government)
3 In Brazil the planning of the transmission system is performed by EPE: the Energy Planning Authority - under the Ministry of Mines and Energy

55
ANNEX 4: GLOSSARY
Abbreviation Description
DLR Dynamic Line Rating
HVAC High Voltage Alternating Current
HVDC High Voltage Direct Current
ISO
Independent System Operator, i.e. the system operator does not own
the transmission assets
Maximum Demand
The highest power demand reached on a power system in a specified
period
OHL Overhead line
RES Renewable Energy Systems
SMART Smart grid technology
SO System operator
SPS Special Protection Schemes
TSO
Transmission System Operator, i.e. the system operator owns the
transmission assets.
TPC Technical Planning Criteria, i.e. planning reliability and security criteria
UGC Underground Cable
VIU Vertically Integrated Utility
WG Working group
Table A4-1: Glossary of Terms

56
Region
MaximumDemand(MW)
NumberofProjects
CapitalSpendperCountry
(€'m)
CapitalSpend/MWDemand
(€'m/MW)
No.Projects<€50'm
No.Projects>€50'm
No.Projects>€150'm
No.Projects>€500m
No.ofProjectsforwhichNo
InformationProvided
%ofETCAllocatedto
CIRCUITS
%ofETCAllocatedto
SUBSTATIONS/TERMINALS
Respondent 1 Non-State
Integrated
Utility
2,680 10 257 0.096 9 1 0 0 0 43% 58%
Respondent 2 State TSO 4,005 2 351 0.088 1 1 1 0 0 45% 55%
Respondent 3 State ISO 6,570 3 700 0.107 1 2 2 0 0 No Data No Data
Respondent 6 State ISO 4,626 10 1,462 0.316 3 7 3 1 0 54% 47%
Respondent 8 State
Integrated
Utility
36,664 10 2,855 0.078 6 4 3 2 0 29% 71%
Respondent 9 State
Integrated
Utility
10,885 10 716 0.066 5 5 1 0 0 56% 45%
Respondent 10 State
Integrated
Utility
33,680 9 No Data No Data 0 0 0 0 9 No Data No Data
Respondent 11 Non-State TSO 13,200 8 532 0.040 6 2 1 0 0 46% 54%
Respondent 12 State TSO 10,612 10 1,551 0.146 0 10 4 0 0 70% 30%
Respondent 13 State ISO 10,994 7 71 0.006 2 0 0 0 5 0% 100%
Respondent 14 Non-State
Integrated
Utility
15,435 4 No Data No Data 0 0 0 0 4 No Data No Data
Respondent 15 State TSO 17,442 8 4,220 0.242 0 3 3 2 5 87% 13%
Respondent 16 State TSO 22,129 10 2,383 0.108 1 9 5 2 0 No Data No Data
Respondent 17 State TSO 24,780 No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data
Respondent 18 Non-State ISO 75,000 10 6,948 0.093 0 10 9 3 0 63% 37%
Respondent 19 State
Integrated
Utility
663,636 No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data
Respondent 20 State ISO 147,769 10 No Data No Data 0 0 0 0 10 No Data No Data
Respondent 21 State TSO 91,720 10 1,999 0.022 1 6 4 0 3 No Data No Data
Respondent 22 Non-State TSO 55,000 8 4,250 0.077 1 7 7 4 0 77% 23%
Respondent 23 Non-State TSO 44,100 24 No Data No Data 0 0 0 0 24 No Data No Data
Respondent 24 Non-State TSO 56,164 8 1,670 0.030 0 3 3 1 5 No Data No Data
Total 1,363,823 200 31,333 60 75 49 15 65
Company(SO)Ownership
AssetOwnership
Project Capital Cost
(No. Of Projects)
Project Assets
(% of Capital Spend)
ANNEX 5: DATA SUMMARY

57
Region
Security/Reliability/Qualityof
Supply
SoS:N-1(voltagestability)
SoS:N-1(transientstability)
SoS:N-1(thermaloverload)
SoS:N-1(Other)
SoS:N-1-1
SoS:N-2
SoS:CapacityProvision
MitigateLoopFlows
Station-ThermalCapacity
TransientStability
VoltageStability
Short-Circuit
NoAdditionalInformationProvided
NewConnection(Loador
Generator)
Connection:Conventional
Generators
Connection:RES
Connection:Demand
SystemReinforcementfor
GenerationIntegration
Economic:ConstraintsCost
Reduction/NetMarketBenefits/
Optimisation
MarketAccessbetweenPrice
Arease.g.Interconnection
NetworkSecurityAddressing
LoopFlows
Statutory-Health&Safety
AssetReplacement
AssetUpgrade
Respondent 1 10 0 0 0 10 0 0 0 0 0 0 0 0 0 10 0 0 0 10 0 0 0 0 0 0 0 0 0 10
Respondent 2 2 0 0 0 0 0 0 0 0 1 0 1 0 0 1 0 0 1 0 1 1 0 0 0 0 0 0 0 1
Respondent 3 1 1 0 0 0 0 0 0 0 0 0 0 0 1 1 0 0 0 0 0 1 0 0 1 0 0 0 0 1
Respondent 4 2 0 0 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 2 2 1 0 0 0 0 0 6 2
Respondent 5 9 0 0 0 0 0 0 0 8 0 0 0 0 1 1 0 0 0 1 0 9 2 8 0 0 0 0 2 9
Respondent 6 5 1 0 1 0 2 0 1 0 1 0 1 0 0 5 0 5 0 0 6 2 1 0 2 0 2 0 0 6
Respondent 7 10 0 0 0 0 0 0 0 9 0 0 0 0 1 9 0 0 0 9 10 0 3 9 0 0 0 0 0 10
Respondent 8 6 1 0 0 3 0 0 0 0 0 0 0 0 2 3 1 2 0 0 2 2 0 0 3 2 1 0 1 6
Respondent 9 9 5 0 0 1 0 2 0 0 0 0 0 2 0 8 0 0 0 8 4 0 0 0 0 0 0 0 0 8
Respondent 10 8 0 0 0 0 0 0 0 0 0 0 0 0 8 4 0 0 0 4 0 4 1 0 0 0 0 0 0 4
Respondent 11 8 0 0 0 0 0 0 0 0 0 0 0 0 8 0 0 0 0 0 0 3 3 1 1 0 1 0 0 4
Respondent 12 7 7 1 5 0 0 0 0 0 0 0 0 1 0 1 0 0 1 0 0 1 0 0 2 0 2 0 0 1
Respondent 13 3 0 0 0 0 0 0 0 3 3 0 0 1 0 4 1 1 1 1 2 4 0 3 0 0 0 0 0 6
Respondent 14 4 0 0 0 3 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Respondent 15 8 0 0 0 5 0 5 0 5 0 0 0 0 0 0 0 0 0 0 3 3 3 3 0 0 0 0 1 7
Respondent 16 7 0 0 0 4 0 0 3 0 1 0 0 0 0 0 0 0 0 0 4 7 2 0 1 0 0 2 0 8
Respondent 17 No Data No Data No DataNo Data No Data No Data No Data NoData NoData
Respondent 18 6 2 5 2 0 0 0 0 1 0 0 0 0 0 8 1 3 3 1 6 3 0 1 0 0 0 0 0 10
Respondent 19 No Data No Data No DataNo Data No Data No Data No Data NoData NoData
Respondent 20 9 0 0 0 0 1 0 0 4 0 2 3 0 3 4 4 0 0 0 2 0 0 4 0 0 0 0 0 9
Respondent 21 3 4 0 0 5 0 0 0 2 0 1 0 0 0 2 0 1 0 1 4 5 3 2 0 0 0 0 1 8
Respondent 22 6 0 0 0 1 0 0 0 0 0 0 0 0 5 5 0 0 0 5 5 3 5 0 1 0 1 0 1 7
Respondent 23 9 1 0 19 0 0 0 0 0 0 0 0 0 0 12 0 0 0 12 13 6 0 0 0 0 0 0 0 13
Respondent 24 6 0 0 0 0 0 0 0 5 1 0 0 0 0 6 2 3 0 1 7 3 3 5 3 0 0 3 1 8
Total 138 22 6 27 32 3 8 4 37 7 3 5 4 31 84 9 15 6 53 71 59 27 36 14 2 7 5 13 138
Expansion, New Build
(No. Of Projects)
Refurbish
(No.ofProjects)
Other-IncludingPoliticalDrivers
(No.ofProjects)
ProjectswithMultipleDrivers
(No.OfProjects)
Note : Sub-categories were included to account for the additional comments provided in order to better understand each category. The data was not used in the analysis.

58
Region
MaximumDemand(MW)
NumberofProjects
DevelopmentPeriodforProjects
<€50'm
>€50'm
>€150'm
>€500m
No.ofProjectsforwhichNo
InformationProvided
SiteorRouteAccess/Space
LocalOpposition/Concerns
StatutoryPlanningProcesses
Novel&Unconventional
TransmissionTechnology
TechnicalObsolesenceof
Equipment/Technology
MinimumIncrementalApproach
LongTermIntegratedStrategic
Basis
RenewableEnergyRelated-
StatePolicy
Respondent 1 Non-State Integrated Utility 2,680 10 34 36 - - 0 10 10 0 1 0 0 0 10 0
Respondent 2 State TSO 4,005 2 39 22 22 - 0 2 2 2 1 0 1 0 2 1
Respondent 3 State ISO 6,570 3 24 60 60 - 0 2 3 3 2 3 0 2 1 2
Respondent 5 State TSO 6,492 9 40 36 - - 0 9 3 9 0 1 1 0 9 0
Respondent 6 State TSO 4,626 10 69 102 119 114 0 10 10 10 10 1 0 0 10 8
Respondent 7 State TSO 4,022 10 44 - - - 0 9 8 9 0 0 0 0 10 7
Respondent 8 State Integrated Utility 36,664 10 33 84 92 102 0 3 3 1 0 2 1 0 0 3
Respondent 9 State Integrated Utility 10,885 10 106 134 100 - 0 10 8 10 3 2 10 0 10 2
Respondent 10 State Integrated Utility 33,680 9 15 - - - 0 0 0 5 0 0 0 0 9 0
Respondent 11 Non-State TSO 13,200 8 No Data No Data No Data No Data 8 4 4 4 1 1 0 0 5 2
Respondent 12 State TSO 10,612 10 - 38 46 - 0 10 10 10 0 0 0 0 10 0
Respondent 13 State ISO 10,994 7 21 - - - 1 1 1 5 0 0 0 0 6 0
Respondent 14 Non-State Integrated Utility 15,435 4 118 - - - 0 2 0 4 0 0 0 0 4 0
Respondent 15 State TSO 17,442 8 No Data No Data No Data No Data 8 1 6 0 2 0 0 0 8 4
Respondent 16 State TSO 22,129 10 120 79 79 102 0 1 7 4 0 0 2 4 6 0
Respondent 17 State TSO 24,780 No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data
Respondent 18 Non-State ISO 75,000 10 - 29 29 39 1 1 6 8 1 0 4 5 10 3
Respondent 19 State Integrated Utility 663,636 No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data No Data
Respondent 20 State ISO 147,769 10 9 - - - 0 0 0 0 0 2 0 0 10 0
Respondent 22 Non-State TSO 55,000 8 36 63 63 78 0 4 3 4 5 1 2 2 7 2
Respondent 23 Non-State TSO 44,100 24 No Data No Data No Data No Data 24 0 24 0 0 0 0 0 7 9
Respondent 24 Non-State TSO 56,164 8 12 12 12 36 5 2 4 8 2 2 0 0 0 5
Total 1,363,823 200 781 835 774 471 52 81 121 113 33 15 23 16 141 51
AssetOwnership
Project Development Period
(No. of Months)
Environmental & Societal
(No. of Projects)
Technical
(No. of Projects)
Financial
(No.ofProjects)
Strategic / General Approach
(No. of Projects)

59
Region
MaximumDemand(MW)
NumberofProjects
ConnectionCharge
StrategicRationale
EconomicAssessment
LeastEconomicCost;LifeCycle
Costing;TimeValueofMoney
(NPV)
MultiCriteriaAnalysis
MarketSimulation-Costof
Constraints
PrivatelyFunded
Respondent 1 Non-State Integrated Utility 2,680 10 0 0 10 10 0 0 0 0
Respondent 2 State TSO 4,005 2 0 0 2 2 0 0 0 0
Respondent 3 State ISO 6,570 3 0 0 0 0 0 0 0 0
Respondent 8 State Integrated Utility 36,664 10 3 1 5 5 0 0 0 1
Respondent 11 Non-State TSO 13,200 8 0 0 0 0 0 0 0 0
Respondent 14 Non-State Integrated Utility 15,435 4 0 0 0 0 0 0 0 4
Respondent 17 State TSO 24,780 No Data No Data No Data No Data No Data No Data No Data No Data No Data
Respondent 18 Non-State ISO 75,000 10 0 0 10 10 10 0 0 0
Respondent 19 State Integrated Utility 663,636 No Data No Data No Data No Data No Data No Data No Data No Data No Data
Total 1,363,823 200 3 2 84 76 37 21 2 98
AssetOwnership
Project Business Case

REVIEW OF DRIVERS FOR TRANSMISSION INVESTMENT DECISIONS

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