Transmission Planning Guidelines - Energy Regulatory Commission

Draft Guidelines for Transmission Planning
March 2012
Prepared for

Table of Contents
ABBREVIATIONS ............................................................................................................... 6
DEFINITION OF TERMS ...................................................................................................... 9
GENERAL STATEMENT ..................................................................................................... 12
1. INTRODUCTION ....................................................................................................... 13
1.1 Introduction ............................................................................................................... 13
1.2 Planning Horizon ........................................................................................................ 13
1.3 Planning Process ........................................................................................................ 14
2. Forecasting ............................................................................................................. 16
2.1 Introduction ............................................................................................................... 16
2.2 Forecast Information .................................................................................................. 16
2.3 Forecasting Methodology ........................................................................................... 17
3. Standards and Criteria ............................................................................................. 19
3.1 Introduction ............................................................................................................... 19
3.2 Performance Standards as per the PGC ....................................................................... 20
3.2.1 System Losses ................................................................................................................................ 20
3.2.2 Congestion .................................................................................................................................... 20
3.3 Planning Criteria and Limits ........................................................................................ 21
3.3.1 Planning for Redundancy .............................................................................................................. 21
3.3.2 Technical Limits ............................................................................................................................. 22
3.3.3 Power Factor Considerations ........................................................................................................ 26
3.3.4 Minimum and Peak Load Demand Considerations ....................................................................... 26
3.3.5 Planning for Disposal of Assets ..................................................................................................... 27
3.3.6 Planning for Generation ................................................................................................................ 27
4. Technical Studies ..................................................................................................... 28
4.1 Introduction ............................................................................................................... 28
4.2 Data Requirement ...................................................................................................... 28
4.3 Load Flow Studies ...................................................................................................... 32
4.3.1 Minimum Data Requirements ....................................................................................................... 32
4.3.2 Criteria and Study Scenarios ......................................................................................................... 33
4.3.3 Load Assumptions ......................................................................................................................... 33
4.3.4 Generation Assumptions ............................................................................................................... 34
4.4 Short Circuit Studies ................................................................................................... 35
4.5 Switching Studies ....................................................................................................... 36
4.6 Voltage Stability ......................................................................................................... 36
4.7 Transient Stability ...................................................................................................... 38
4.7.1 Minimum Data Requirements ....................................................................................................... 38
4.7.2 Criteria ........................................................................................................................................... 38
4.7.3 Methodology ................................................................................................................................. 39
4.7.4 Results ........................................................................................................................................... 41
4.7.5 Transient Instability ....................................................................................................................... 42
4.8 Small Signal Stability .................................................................................................. 43
4.8.1 Minimum Data Requirements ....................................................................................................... 43
Draft as of March 2012 2

4.8.2 Criteria ........................................................................................................................................... 43
4.8.3 Methodology ................................................................................................................................. 44
4.8.4 Results ........................................................................................................................................... 45
4.9 Sub-synchronous Resonance (SSR) Studies .................................................................. 45
4.9.1 Minimum Data Requirements ....................................................................................................... 46
4.9.2 Frequency Scanning ...................................................................................................................... 47
4.9.3 Eigenvalue Analysis ....................................................................................................................... 47
4.10 Generation Facilities ................................................................................................... 48
4.10.1 Integration of Generation Facilities .......................................................................................... 48
4.10.2 Renewable Generation ............................................................................................................. 49
4.10.3 Minimum Data Requirements .................................................................................................. 50
4.10.4 Type of Studies ......................................................................................................................... 50
4.11 Quality of Supply Studies ............................................................................................ 50
4.11.1 Unbalance Studies .................................................................................................................... 50
4.11.2 Voltage Distortion Studies ........................................................................................................ 51
4.12 Right of Way and Environmental Considerations ......................................................... 51
5. Transmission Assets................................................................................................. 52
5.1 Introduction ............................................................................................................... 52
5.2 Transformers ............................................................................................................. 52
5.3 Switchgear ................................................................................................................. 53
5.3.1 PCBs ............................................................................................................................................... 53
5.3.2 Isolators or Disconnecting Switches .............................................................................................. 54
5.3.3 Gas Insulated Switchgear .............................................................................................................. 54
5.4 Transmission Lines ..................................................................................................... 54
5.4.1 Design of Transmission Lines ........................................................................................................ 54
5.4.2 Thermal Limits ............................................................................................................................... 55
5.4.3 Voltage Limits ................................................................................................................................ 56
5.4.4 Conductor Optimization ................................................................................................................ 56
5.5 Capacitors (Series and Shunt) ..................................................................................... 56
5.5.1 General .......................................................................................................................................... 56
5.5.2 Shunt Capacitors ........................................................................................................................... 56
5.5.3 Series Capacitors ........................................................................................................................... 58
5.6 Reactors (Series and Shunt) ........................................................................................ 59
5.6.1 Application of Shunt Reactors ....................................................................................................... 59
5.6.2 Switchgear ..................................................................................................................................... 60
5.6.3 Other Types of Reactors ................................................................................................................ 60
5.7 HVDC Schemes ........................................................................................................... 61
5.8 FACTS Devices ............................................................................................................ 62
5.8.1 SVCs ............................................................................................................................................... 62
5.8.2 STATCOM ...................................................................................................................................... 63
5.8.3 TCSC ............................................................................................................................................... 63
5.8.4 Unified Power Flow Controller (UPFC) .......................................................................................... 64
5.8.5 Thyristor Controlled Breaking Resistor (TCBR).............................................................................. 64
5.9 Busbar ....................................................................................................................... 64
6. Transmission Planning in a Market Environment...................................................... 65
6.1 Introduction ............................................................................................................... 65
6.2 Coordination Among the Regulated Transmmission Entity, Grid Customers, System
Operator and Market Operator ............................................................................................... 65
6.3 Open Access and Grid Planning ................................................................................... 65
Draft as of March 2012 3

6.4 Alleviation of Congestion to Enhance Market Efficiency .............................................. 65
6.5 Market Impact Studies to Assess Impact on WESM of Congestion Alleviation CAPEX
Projects .................................................................................................................................. 66
6.6 Impact of Different Generation Patterns ..................................................................... 66
7. Project Selection and DocumenTation ...................................................................... 67
7.1 Introduction ............................................................................................................... 67
7.2 Project Evaluation ...................................................................................................... 67
7.2.1 Defining the Problem .................................................................................................................... 68
7.2.2 Selecting Potential Solutions ......................................................................................................... 69
7.2.3 Technical Analysis.......................................................................................................................... 70
7.2.4 Market Analysis ............................................................................................................................. 70
7.2.5 Financial Analysis .......................................................................................................................... 74
7.3 Prioritization .............................................................................................................. 78
7.4 Project Documentation .............................................................................................. 78
REFERENCES ................................................................................................................... 81
APPENDIX A: List of Standards used by the Regulated Transmission Entity for Transmission
Line design ..................................................................................................................... 83
Draft as of March 2012 4

Date Issued: 21 March 2012
Document Name: Transmission Planning Guideline rev 8
Document Version:
Project Team:
Name of Project:
Draft Transmission Guideline
Pieter Nel, Machiel Coetzee, Dr Yen-Shong Chiao, Kris Tampinco
Development of Transmission Planning Guidelines
Draft as of March 2012 5

ABBREVIATIONS
ABBREVIATION
A
A
AAC
AAAC
AC
ACSR
AIS
AVR
TERM
Ampere
All Aluminum Conductor
All Aluminum Alloy Conductor
Alternating Current
Aluminum Conductor Steel Reinforced
Air Insulated Switchgear
Automatic Voltage Regulator
B
C
CAPEX
CCC
CPV
CSP
CT
CVC
D
DC
DCF
DDP
DFIG
DOE
DU
Capital Expenditure
Capacitor Commutated Converter
Concentrated Photovoltaic
Concentrated Solar Power
Current Transformer
Constraint Violation Coefficient
Direct Current
Discounted Cash Flow
Distribution Development Plan
Double-fed Induction Generator
Department of Energy
Distribution Utility
E
EENS
Expected Energy Not Supplied
EPIRA Electric Power Industry Reform Act (R.A. No. 9136)
E’q
Voltage behind Transient Reactance
ERC
Energy Regulatory Commission
F
FACTS
G
GIS
GTO
H
HVAC
HVDC
Hz
I
IGBT
Flexible AC Transmission System Devices
Gas Insulated Switchgear
Gate Turnoff
High Voltage Alternating Current
High Voltage Direct Current
Hertz
Insulated Gate Bipolar Transistor
J
K
kA
km
kV
kWh
Kilo Ampere
Kilometer
Kilovolt
kilo Watt Hour
Draft as of March 2012 6

ABBREVIATION
L
LC
LV
LWAP
M
MAE
MAPE
MDOM
MOV
ms
MSE
MTS
MV
MVA
MVAr
MW
MWH
N
NGCP
NPV
O
OPGW
P
PCB
PDM
PDP
PEP
PGC
PhP
PSM
PSS
PSS/E
pu
PV
TERM
Inductive-Capacitive
Low Voltage
Load Weighted Average Price
Mean Absolute Error
Mean Absolute Percentage Error
Market Dispatch Optimization Model
Metal Oxide Varistor
Milliseconds
Mean Squared Error
Main Transmission System
Medium Voltage
Megavolt Ampere
Megavolt Ampere Reactive
Megawatt
Megawatt Hour
National Grid Corporation of the Philippines
Net Present Value
Optical Fiber Ground Wire
Power Circuit Breaker
Price Determination Methodology
Power Development Program
Philippine Energy Plan
Philippine Grid Code
Philippine Pesos
Price Substitution Methodology
Power System Stabilizers
Power System Simulator for Engineering
Per Unit
Photovoltaic
Q
R
RMS
RMSE
RTWR
RTU
S
SCO
SIL
SPS
SRMC
SSE
SSR
STATCOM
SVC
T
TCBR
Root-Mean-Square
Root Mean Squared Errors
Rules for Setting Transmission Wheeling Rates
Synchronous Condenser
Surge Impedance Loading
Special Protection System
Short Run Marginal Cost
Sum of Squared Errors
Subsynchronous Resonance
Static Condenser or Compensator
Static VAr Compensator
Thyristor Controlled Breaking Resistor
Draft as of March 2012 7

ABBREVIATION
TCR
TCSC
TDP
TIS
TSC
TOSP
U
UPFC
V
VAr
VSC
VT
W
WESM
TERM
Thyristor Controlled Reactor
Thyristor Controlled Series Capacitors
Transmission Development Plan
Torsional Interaction Susceptibility
Thyristor Switched Capacitor
Time of System Peak
Unified Power Flow Controller
Volt Ampere Reactive
Voltage Sourced Converter
Voltage Transformer
Wholesale Electricity Spot Market
X
Y
Z
Draft as of March 2012 8

DEFINITION OF TERMS
Circuit means any transmission line connecting any two points on the network.
Congestion cost means the additional costs that buyers of electricity have to pay or the reduced
economic benefits that buyers of electricity have to endure due to transmission congestion. In the
context of the Market Dispatch Optimization Model (MDOM) or the Price Determination Methodology
(PDM) for the Wholesale Electricity Spot Market (WESM), it is the difference between the
Unconstrained Economic Benefit and the Constrained Economic Benefit.
Constrained economic benefit means the objective function value of the MDOM or the Market
Simulation Model when there is transmission congestion
Customer means a person or entity e.g. generation facility, distribution utility, retail electricity supplier,
end-user, whose system or equipment is directly connected to the grid and who purchases or receives
or is seeking to purchase or receive transmission services from the Regulated Transmission Entity.
Double Contingency or N-2 Contingency means that a second circuit or item of plant is tripped and
locked out of service from the N-1 contingency condition and no corrective action has been taken, i.e.
the two contingency events are simultaneous or quickly follow each other.
Generating Unit means a conversion apparatus including auxiliaries and associated equipment,
functioning as a single unit, which is used to produce electric energy from some other form of energy.
Generation Facility means a facility consisting of one or more generating units, where electric energy
is produced from some other form of energy by means of a suitable apparatus.
Grid or Transmission System means the high voltage backbone system of interconnected
transmission lines, substations and related facilities, located each in Luzon, Visayas and Mindanao.
IEC standard means the standards approved and published by the International Electrotechnical
Commission which represents international standards for electro-technical equipment.
Issues Paper means the document that will be published by the Energy Regulatory Commission
(ERC) pursuant to Article VII of the Rules for Setting Transmission Wheeling Rates (RTWR) which
contains the ERC’s initial views on the issues raised by the pending regulatory reset process as well
as specifies the information (and corresponding timeline) to be provided by the Regulated
Transmission Entity for purposes of the regulatory reset process.
Item of plant means any equipment connected at a substation, namely transformers, capacitors,
reactors and Static VAr Compensators (SVCs). It also means any generation facility connected to the
grid.
Maintenance Contingency or N-1-1 Contingency means that a second circuit or item of plant is
tripped and locked out of service from the N-1 contingency condition, but corrective action in the form
of re-dispatch of generation, transformer tapping or the switching in or out of plant such as capacitors
or reactors has taken place to comply with technical limits and mitigate the effects of the second
contingency.
Market Dispatch Optimization Model (MDOM) means the model set out in Section 3.6 of the WESM
Rules.
Draft as of March 2012 9

Market Operator means the group responsible for the operation and administration of the WESM in
accordance with the market rules.
Market Simulation Model means the model which is used by the Regulated Transmission Entity to
simulate the dispatch and pricing outcomes, developed based on the MDOM and the PDM.
Objective function means the objective function specified in Section 4.2 “Basic Algorithm of the
MDOM” of the PDM, which maximizes the economic benefit from trading of electricity.
Price Determination Methodology (PDM) means the ERC approved document of the same name
which sets out the principles by which energy and reserves in the WESM are priced and provides the
specific computation formula that will enable the market participants to verify the correctness of the
charges being imposed.
Price Substitution Methodology (PSM) means methodology that details the determination of the
substitute prices and quantities to be used for settlement of energy transactions in trading intervals
where undesirable market pricing situations occur.
Regulated Transmission Entity means the entity responsible for providing regulated transmission
services who is currently the National Grid Corporation of the Philippines (NGCP) who has been
awarded the concession contract to operate and maintain the Philippines’ transmission grid. For this
guideline, the Regulated Transmission Entity shall also mean the entity responsible for the expansion
needs of the transmission system through efficient and effective grid planning.
Regulatory Reset Process means the process set out in Article VII of the RTWR which includes
consultation in respect of the ERC’s proposals for the price control arrangements that are to apply to
the Regulated Transmission Entity for the relevant regulatory period.
Revenue Application means the document submitted by the Regulated Transmission Entity to the
ERC which contains all the information specified by the ERC in its Issues Paper that will serve as its
application for a new revenue cap for the relevant regulatory period.
Single Contingency or N-1 Contingency means that one single circuit or one item of plant is tripped
and locked out of service, or switched out of service manually for planned maintenance or other
purposes, from the system healthy condition. On a double circuit or multi-circuit line, a Single
Contingency or N-1 Contingency shall mean loss of only one circuit, and not the entire structure.
Special Protection System (SPS) means a system intended to detect abnormal transmission system
conditions and designed to take automatic, corrective and pre-planned action to provide suitable grid
performance.
System Healthy means the normal operation of the grid with all circuits and items of plant available
and in service, unless switched out for voltage control or real power balance.
System Operator means the party responsible for generation dispatch, or the implementation of the
generation dispatch schedule of the market operator, the provision of ancillary services, and operation
to ensure safety, power quality, stability, reliability and security of the grid.
Transmission congestion is a situation where, because the transmission limit of a transmission line
or the capacity of a transformer is reached and no more power may be transmitted through this line or
transformer, cheaper power from a generating unit cannot be dispatched and transmitted through this
line or transformer and instead more expensive power has to be dispatched to meet the demand.
Draft as of March 2012 10

Unconstrained benefit means the objective function of the MDOM or the Market Simulation
Model when there is no transmission congestion or the transmission limitation is relaxed.
Draft as of March 2012 11

GENERAL STATEMENT
This document serves as a guide to the Regulated Transmission Entity of the Philippines in planning
its transmission network and to aid in the preparation of the capital expenditure (CAPEX) forecasts in
the Revenue Application that it must submit to the Energy Regulatory Commission (ERC) prior to each
regulatory period. It is intended that the information to be submitted to support the Revenue
Application will have a similar content and structure to the Transmission Development Plan (TDP) that
will be submitted to the Department of Energy (DOE) but may include additional information specific to
the requirements set out by the DOE and the Philippine Grid Code (PGC).
The requirements set out in this guideline are the minimum requirements of the ERC but do not
replace or supersede any additional requirements set out in the Rules for Setting Transmission
Wheeling Rates (RTWR) and the PGC. In addition, the requirements set out in this guideline should
not be interpreted as overriding the responsibility of the Regulated Transmission Entity to determine
and justify the CAPEX needed to provide the level of service its consumers expect.
Draft as of March 2012 12

1. INTRODUCTION
1.1 INTRODUCTION
Efficient and effective grid planning is critical for maintaining the quality of service expected
from the Regulated Transmission Entity as well as in managing the growth of the power
system. Such planning process includes assessments that will assist in ensuring that the
Regulated Transmission Entity’s assets are fully leveraged and that availability and quality of
supply is not sacrificed. The processes detailed in this guideline will aid the Regulated
Transmission Entity in identifying solutions to network problems as well as prioritizing the
improvements by undertaking the necessary analysis that will ensure the appropriate balance
between the overall cost of a project and the expected benefit to the customers.
The RTWR 1 requires the Regulated Transmission Entity to provide its forward forecasts of its
proposed annual CAPEX for each year of the regulatory period. Such forecasts will be
reviewed as to whether it is cost effective; reasonably efficient from a design and
implementation point of view; and is likely to support the forecast growth in customer, coincident
peak demand and energy delivered to enable the Regulated Transmission Entity to at
a minimum meet its target levels of performance. Furthermore, the PGC 2 identifies that the
Regulated Transmission Entity has lead responsibility for grid planning and has further
specified the required technical studies and planning procedures. From these requirements it
is apparent that the Regulated Transmission Entity should have an accurate and robust
planning process in place not only to support its proposed CAPEX but also to align with the
objectives of the Electric Power Industry Reform Act 3 (EPIRA) to set an efficient grid planning
process in order to ensure the quality, reliability, security and affordability of electrical
transmission services.
This guideline was developed consistent with the requirements of the PGC. The document
specifies standards and criteria for grid planning as well as explains the required technical
studies not only taking into account the power quality requirements in the PGC but also
considering the best practices of transmission entities in other jurisdictions. Moreover, to aid
the Regulated Transmission Entity in planning transmission projects, this guideline also
includes information on planning transmission equipment; planning in a market environment;
and how to evaluate as well as prioritize projects.
1.2 PLANNING HORIZON
The RTWR specifies that the electricity transmission system planning horizon is fifteen (15)
years or as otherwise determined by the ERC based on reasonable planning policies. Thus,
for purposes of grid planning by the Regulated Transmission Entity, long-term studies
employing a planning horizon of fifteen (15) years (unless revised by the ERC), are required to
be conducted in order to determine the most beneficial technologies to serve long-term
system requirements and identify strategic power corridors. The same planning horizon shall
be utilized for evaluating the expected level of use of transmission assets in order to manage
the effect of optimization on CAPEX projects.
1 Rules for Setting Transmission Wheeling Rates for 2003 to around 2027, Energy Regulatory Commission, Philippines,
September 2009.
2 Philippine Grid Code Amendment No. 1, Grid Management Committee, Energy Regulatory Commission, Philippines, April
2007.
3 Electric Power Industry Reform Act (Republic Act No. 9136), Congress of the Philippines, July 2000.
Draft as of March 2012 13

1.3 PLANNING PROCESS
It is the intent of this guideline to set an effective planning process in order to ensure
sustainability and efficiency of transmission services which is the primary objective of
regulation. Moreover, in relation to the regulatory reset process for the Regulated
Transmission Entity, this guideline will aid in the preparation of the proposed CAPEX referred
to in Section 5.10 of the RTWR which forms part of the Revenue Application to be submitted
by the Regulated Transmission Entity to the ERC. Such Revenue Application will be submitted
at the date determined by the ERC after reviewing all the issues raised following the release of
the Issues Paper. Pursuant to Section 7.1.2 of the RTWR, the Issues Paper will be published
not less than 21 months prior to the start of each regulatory period. The Third Regulatory
Period has commenced on January 1, 2011 and will end on December 31, 2015. Thus, it is
expected that the Fourth Regulatory Period will commence on January 1, 2016.
The RTWR and the Issues Paper specifies the minimum requirements for CAPEX
applications. To further assist the Regulated Transmission Entity in its application to the ERC,
this guideline details the specific process the Regulated Transmission Entity has to follow in
formulating project requests keeping in mind issues relating to the technical, environmental
and economic aspects of the project.
Transmission Development Plan (TDP)
While this guideline is intended to assist in the regulatory reset process, it is expected that
having an effective planning process in place will also assist in the preparation of the TDP
given that as per Section 10(a) of the EPIRA, the TDP is primarily a plan for managing the
transmission system through efficient planning.
The main difference between the TDP and the forecast CAPEX application is that the TDP is
prepared annually by the Regulated Transmission Entity to be submitted for approval to the
DOE for integration into the Power Development Program (PDP) and the Philippine Energy
Plan (PEP). On the other hand, the forecast CAPEX application is prepared once every
regulatory reset. It should be noted however that any plan for expansion or improvement of
transmission facilities is required to be approved by the ERC pursuant to Section 10(c) of the
EPIRA,
Another difference between the forecast CAPEX and the TDP is that the forecast CAPEX
considers only projects for the next five (5) years of the regulatory period while the TDP
covers a 10-year plan. The Regulated Transmission Entity has however indicated that the first
years of the TDP normally constitute the CAPEX approved by the ERC for the Regulatory
Period while the latter years of the 10-year period are indicative projects.
The Regulated Transmission Entity is required under the EPIRA to consult electric power
industry participants in the preparation of the TDP. In relation to grid planning, and as also
indicated below, it is recommended that the grid users, market operator and system operator
also be consulted during the planning process in order to assist the Regulated Transmission
Entity in identifying congestion problems that may result in increased electricity prices due to
transmission congestion.
Philippine Grid Code (PGC)
Section 5.2.1 of the PGC states that the Regulated Transmission Entity shall have lead
responsibility for grid planning including:
Draft as of March 2012 14

a) Analyzing the impact of the connection of new facilities;
b) Planning expansion of the grid to ensure its adequacy to meet forecasted demand
and the connection of new generating plants; and
c) Identifying congestion problems that may result in increased outages or raise the
cost of service significantly.
It is worth emphasizing that while the lead responsibility falls under the Regulated
Transmission Entity, coordination with grid users, the market operator and the system
operator is necessary during the planning process (and not only during real time) in order to
assist in identifying congestion problems that may result in increased electricity prices due to
transmission congestion. This need is further explained in Section 6 of this guideline.
Consistent with Chapter 5 of the PGC, Section 4 of this guideline specifies the different grid
planning studies required to be conducted by the Regulated Transmission Entity in order to
ensure the safety, reliability, security and stability of the grid. Section 4 also includes other
studies deemed necessary to efficiently perform the responsibilities of the Regulated
Transmission Entity. Moreover, Section 4 of this document also details the data requirements
for the different types of planning studies to be undertaken by the Regulated Transmission
Entity.
Draft as of March 2012 15

2. FORECASTING
2.1 INTRODUCTION
Forecasting of future requirement is vital to efficient grid planning. Determination of
transmission capacities is highly dependent on accurate energy and load demand forecasting
of the transmission system. From a forecasting standpoint, it shall be the objective of the
Regulated Transmission Entity to match load demand with capacity within the criteria set by
the PGC and this guideline in order to meet the expected peak load demand of the grid.
Underestimating load forecasts could lead to under capacity which would then affect the
quality of service provided by the Regulated Transmission Entity, while overestimating
forecasts could lead to spending more money on CAPEX or to inefficient phasing of
investments.
From the above, it is clear that it is an important objective of the Regulated Transmission
Entity to accurately predict future loads and the first step to efficient forecasting is identifying
the most appropriate forecasting technique. Forecasting can be broadly classified in terms of
time frames or forecast periods which are: long term (one (1) to ten (10) years), medium term
(one (1) day to one (1) year) and short term (up to one (1) day). 4 The level of forecast certainty
differs for the different forecast periods, but for purposes of the Revenue Application the long
term forecast would be required.
The Regulated Transmission Entity has indicated that it requires two (2) interrelated levels of
forecast; an overall grid forecast which is used to determine the need for transmission line
expansion, and a major substation forecast which will be used to determine transformer
capacity additions.
2.2 FORECAST INFORMATION
Customers are required as per Section 5.4 of the PGC to provide the Regulated Transmission
Entity with its energy and load forecasts for the five (5) succeeding years. Customers include
private distribution utilities, electric cooperatives and other users directly connected to the grid.
In the case of distribution utilities (DUs), such projections are utilized in the preparation of the
Distribution Development Plans (DDP) which are annually submitted to the DOE. Forecast
information of other customers are also provided to the DOE and all these projections are
used to develop the forecasts for the PDP.
For the purpose of developing the TDP, the DOE provides the Regulated Transmission Entity
with the overall grid forecasts disaggregated into Luzon, Visayas and Mindanao.
In relation to the regulatory reset process, given that the timeframe for preparing the Revenue
Application differs with the timeframe for the development of the TDP, the Regulated
Transmission Entity is encouraged to develop its own forecasts to be used in the
determination of projects for the next regulatory period. However, if the DOE forecasts are
available, the Regulated Transmission Entity is then required to perform a sensitivity analysis
of the two (2) forecasts (that of DOE and that of the Regulated Transmission Entity) and
4 International Journal of Systems Science volume 33, “Electric Load Forecasting: Literature Survey and Classification of
Methods”, H. Alfares and M. Nazeeruddin, United Kingdom, 2002.
Draft as of March 2012 16

present the results of the analysis to the ERC in relation to the affected CAPEX projects as
part of its Revenue Application.
In terms of the forecasts required for the Market Simulation Model, it is recommended that the
relevant historic load data e.g. hourly load for each modeled node, are obtained from the
market operator for the purpose of preparing the forecast load profile or load duration curve for
the forecast years.
In order to ensure consistency with the DDP, PDP, as well as with the forecasts used in the
WESM, the Regulated Transmission Entity should not alter any forecasts provided by DUs for
use in the development of its own forecasts. However in the review of the submitted forecasts,
the Regulated Transmission Entity is encouraged to clarify any issues with regards to the
forecasts provided by the DUs and await any revision to the forecasts if necessary.
2.3 FORECASTING METHODOLOGY
Forecasting models can be divided into statistically based and intelligence-based models and
all have different characteristics, features and strengths. The selection of the most suitable
forecasting model is highly dependent on the following parameters: forecast time frame, data
availability, the accuracy and cost of the forecast, the application and purpose of the forecast. 5
Regarding the forecast time frame, as indicated in Section 2.1 above, the forecasting
technique required in relation to the regulatory reset process of the Regulated Transmission
Entity is long term forecasting which is intended for applications in relation to capacity
expansion as well as studies on the return of capital investments. The long term forecast is
required for a period of fifteen (15) years, which is the planning horizon set as per the RTWR
unless it is otherwise revised by the ERC, which will then be used to develop the capital
requirement for the next five (5) years which is the prescribed time frame for a regulatory
period.
Long term forecasts take into account historical load data, the number of customers in
different categories, the economic and demographic data and their forecasts, and other
factors. Typically, power utilities serve customers of different types such as residential,
commercial and industrial, and different factors affect the forecasting of each class. However,
in the case of the Regulated Transmission Entity, there appears to be no requirement to take
into account the different types of customers since these will already be taken into account in
the submitted forecasts by the DUs. Given this, the focus of the Regulated Transmission
Entity will be on historical load data, the economic and demographic data and their forecasts,
and other factors.
Statistically based methods forecast the current value of a variable by using explicit
mathematical combinations of the previous values of that variable and, possibly, previous
values of exogenous factors. 6 Long term forecasting using statistically based models require
years of economic and demographic data and is affected by environmental, economic, political
and social factors. The econometric approach is broadly used for long term forecasting which
combines economic theory and statistical techniques for forecasting electricity load demand.
The approach estimates the relationships between energy consumption and factors
5 Business Intelligence in Economic Forecasting: Technologies and Techniques, F. Elakrmi and N. A. Shikhah, Amman
University, Jordan.
6 Power System Planning, Howard Technology, Middle East.
Draft as of March 2012 17

influencing consumption. The relationships are typically estimated by the least-squares
method or time series methods. 7
It should be noted that the availability of accurate and consistent information is an important
factor in the determination of which model to use. One reason for this is the difficulty in
forecasting demographic and economic factors versus that of load forecasting. 8 If accurate
information on economic and demographic factors is not readily available, then the
econometric approach may not be the most suitable model. Extrapolation models which
involve fitting trend curves to basic historical data are simple and easy to use however is most
appropriate for short term projections because it ignores the possible interaction of load
demand with other economic factors. 9 Thus, for long term forecasting using extrapolation
models, it is appropriate to take into account discounting the earliest elements of the forecast
by incorporating weighting factors (suitable weighting factors are from 0.25 to 0.90) in the
calculation of the least squares (best fit) solution. 10
Intelligence-based models e.g. Fuzzy Systems, attempts to model the human reasoning
process at a cognitive level which requires expert knowledge. The algorithms associated with
intelligence-based models neither require a mathematical model that will map inputs to
outputs nor require precise inputs. 11
Results of studies undertaken in different countries have indicated differences in terms of what
is most appropriate for long term forecasting. From other studies, statistically based models
are recommended to be used while there are also studies that indicate that intelligence-based
models prove superior to statistically based models.
It is the Regulated Transmission Entity’s responsibility to select the most appropriate model
(or models, as several load forecasting methods may be used in parallel), whether it be
statistically based, intelligence based or a combination of different model types. To assist in
the selection, the Regulated Transmission Entity shall test the acceptability or the accuracy of
the algorithms. There are different measures to test the accuracy of a model e.g. the mean
absolute error (MAE), mean absolute percentage error (MAPE), sum of squared errors (SSE),
mean squared error (MSE) and root mean squared errors (RMSE). 12 The MAPE and the SSE
are the most widely used for load forecasting, and in such accuracy tests, the difference
between the actual load and forecast load is calculated and the model with an error ranging
from 2-5% is considered as exhibiting good performance. Among the models that have
passed the test on accuracy, the model with the least error is the most suitable. The results of
the test on the model selection shall be documented by the Regulated Transmission Entity
and shall be made available during the review of the expenditure forecasts. Such
documentation should also be made available earlier in the regulatory reset process in the
event that the ERC requires such information to be submitted as part of the Revenue
Application.
7 Applied Mathematics for Power Systems, E. A. Feinberg and D. Genethliou, State University of New York, New York.
8 Modern Power System Analysis, D.P. Kothari, I.J. Nagrath, New York, 2008.
9 Demand Forecasting for Electricity, N. Bohr.
10 Computer Analysis Methods for Power Systems, G.T. Heyat, New York.
11 Fuzzy Ideology based Long Term Forecasting, J. H. Pujar, World Academy of Science, Engineering and Technology, India.
12 Long Term Energy Consumption Forecasting Using Genetic Programming, K. Karabulut, A. Alkan, A. Yilmaz, Yasar
University, Turkey, 2008.
Draft as of March 2012 18

3. STANDARDS AND CRITERIA
3.1 INTRODUCTION
The overall goal of the planning activities can be expressed as follows:
The planning of the grid or transmission system shall aim at the identification of the least-cost
alternative, or the alternative which maximizes the net benefit with due attention being paid to
major uncertainty factors and providing adequate security and reliability.
Grid planning has to be based on realities concerning geographical conditions, technical
status and possibilities, and the sizes and locations of the power markets. Due to the fact that
the Philippines’ power system is covering a widespread geographical area with scattered
population and long distances between the most inexpensive power resources and the power
market, integrated generation and grid planning has to be performed. Thus, grid planning also
has to be undertaken with the intention of identifying projects in close coordination and
cooperation with not only with DUs but more importantly with generation facilities.
The main task for the power industry in the Philippines would be to supply the customers with
electric power, in sufficient amount and with an economically viable supply quality.
In most countries, there is substantial competition between the different industry sectors of the
society to get capital for necessary investment and rehabilitation projects. The Philippines is in
this respect no exception. Since the power industry is so capital intensive, the requirements on
power supply reliability should generally not be too rigid; the stricter the criteria the higher the
investment to be called for.
A basic principle of grid planning is that all equipment should be within normal capacity ratings
and normal voltage limits when the system is operating with all scheduled elements in service
and is not experiencing faults or other abnormal faults or disturbances.
Furthermore, the system should be capable of operating within emergency capacity ratings
and emergency voltage limits immediately following a system fault that results in the loss of a
single element (N-1). The system operator will then manage the transmission system to return
to a healthy operating condition as soon as possible to ensure continuity of supply within the
capacity ratings and voltage limits.
An objective of this guideline is to use planning criteria also recognized in other jurisdictions to
assist the Regulated Transmission Entity in developing a secure and reliable transmission
system. The planning criteria described in this guideline shall be used for any new
transmission system development project in the Philippines.
It is the Regulated Transmission Entity’s 13 responsibility to identify many possible solutions to
satisfy the need and to comply with the planning criteria. It is also the task of the Regulated
Transmission Entity to rank the possible solutions in such a way that it can be acceptable to
the environment, complete the implementation in the time specified and that it is the best
solution with a good balance between technical fit and economic viability (techno-economic).
13
The Regulated Transmission Entity as the “system planning engineer” is responsible for the expansion needs of the
transmission system by conducting the appropriate power system studies to comply with the requirements as set out in this
guideline and the PGC.
Draft as of March 2012 19

The transmission system plan must comply with all the statutory and technical limits as
documented in the PGC and all other relevant standards and specifications that may be
applicable in the Philippines.
3.2 PERFORMANCE STANDARDS AS PER THE PGC
The Regulated Transmission Entity must ensure that the transmission system is designed to
comply with the quality requirements as stipulated in Chapter 3 of the PGC.
3.2.1 System Losses
The transmission system losses are a major concern to any utility. The aim for any system
planning engineer is to reduce the system losses as far as technically possible in the process
of developing the transmission system. It is the task of the Regulated Transmission Entity to
calculate the system losses for all possible alternatives considered and to use these results as
one of the drivers to determine the best techno-economic solution for system development.
Typically the Regulated Transmission Entity will calculate the impact on system losses for the
life time of the expected new project infrastructure as part of the project justification.
System loss shall be classified into three categories: Technical loss, non-technical loss and
administrative loss.
The technical loss shall be the aggregate of conductor loss, the core loss in transformers, and
any loss due to technical metering error.
The non-technical loss shall be the aggregate of the energy loss due to meter-reading errors
and meter tampering.
The administrative loss shall include the energy that is required for the proper operation of the
Grid.
3.2.2 Congestion
Congestion in relation to operating in a market environment has yet to be defined in the PGC.
For the purpose of grid planning as set out in this guideline, transmission congestion shall
mean a situation where, because the transmission limit of a transmission line or the capacity
of a transformer is reached and no more power may be transmitted through this line or
transformer, cheaper power from a generating unit cannot be dispatched and transmitted
through this line or transformer and instead more expensive power has to be dispatched to
meet the load demand.
While Chapter 3 of the PGC does not contain standards in relation to transmission congestion
as defined above, it is primarily the Regulated Transmission Entity’s responsibility to identify
the congestion problems that may result in increased outages or raise the cost of service or
the electricity prices due to transmission congestions significantly. This is further explained in
Section 6 of this guideline.
Draft as of March 2012 20

3.3 PLANNING CRITERIA AND LIMITS
3.3.1 Planning for Redundancy
The planning for full redundancy 14 of any transmission system will lead to high CAPEX and is
typically not economically viable.
Reliability Criteria
The degree of reliability of the transmission system or of the supply to the customer depends
on the probability to interrupt the supply and the probable load that will not be supplied during
an outage. Furthermore, the reliability will also depend on the reliability required by the
customer or the type of load involved at the point of supply.
It is standard practice to design any transmission system to comply with N-1 contingency
criteria. It is important that the backbone of the grid complies with the N-1 contingency criteria
in order to ensure a secure, reliable and stable operation of the Regulated Transmission
Entity. The compliance to N-1 contingency is normally difficult for small utilities, isolated
networks and isolated regions and more achievable for larger utilities. It is a costly
requirement and not necessarily an economical way to operate a relatively small utility or a
utility that is constraint with capital.
The supply to large loads or customers is normally based on a firm power supply which is
economically justified due to the size of the load and the impact on operating and maintaining
continuity of supply when this amount of load is lost to the system. This is also applicable to
the connection of generation facilities to the grid where the infrastructure required is normally
justified by the economic impact if a power station is lost during a single outage.
The minimum redundancy requirement specified by the PGC is to provide firm supply
throughout the system, i.e. the transmission system must be designed to meet specified limits
and criteria for at least any N-1 contingency on a deterministic basis.
A system meeting the N-1 or higher contingency criterion must comply with all relevant limits,
under all system loading conditions from peak load to light load, with any single transmission
or other component(s) (including generation components) out of service.
An N-1 contingency criterion is based on the status and impact on the transmission system
following the loss of any circuit. The transmission system must still comply with all the related
limitations imposed on the Regulated Transmission Entity:
1. The electrical and thermal ratings of equipment will not be exceeded;
2. Stable control of system voltage will be maintained within acceptable levels;
3. Stable control of frequency will be maintained within acceptable levels;
4. Synchronous stability will be maintained; and
5. Load will not be shed 15 .
14 Full redundancy of the power system means that the power system will be able to operate within its specified thermal and
voltage limits and with an acceptable quality of supply during any contingency that could develop in the power system.
15 Under some circumstances, load may be shed if it is a dispatchable load to limit the effects of the fault.
Draft as of March 2012 21

The requirement above is applicable to all loading conditions, such as peak and minimum
loading, night and day, any season of the year as well as with different generation scenarios.
Contingency conditions must therefore be tested against different generation and loading
scenarios.
N-1-1 contingency could, as described below, assist to minimize the economic impact to
comply with the criteria of N-1. As an example of N-1-1, a supplementary action 16 could be
activated once an N-1 contingency exist which, to a limited extent, endeavors to mitigate the
impact of the N-1 contingency. The impact on the transmission system could be the
overloading of transmission lines or violation of the system voltages or system frequency
limits. Therefore, a second circuit or any element of the transmission system is tripped and
locked out of service as part of the N-1 contingency condition, but typical corrective action in
the form of re-dispatch of generation, tripping of load, transformer tapping or the switching in
or out of plant such as capacitors or reactors has taken place to comply with technical limits
and mitigate the effects of the second contingency.
N-2 Provision
While it is inevitable for transmission systems to experience the tripping of a second circuit,
planning for N-2 may not be financially viable and therefore not recommended. The Regulated
Transmission Entity shall then undertake studies that will assist in identifying the risk of such a
scenario and plan to mitigate such risks through Special Protection Systems (SPS). It should
however be noted that although SPS are relatively cheaper and faster to put into service, grid
planning should not be fully reliant on SPS solutions as SPS also poses certain risks to
system security. Thus it is important for the Regulated Transmission Entity to develop a
comprehensive process in evaluating, designing and maintaining SPS.
3.3.2 Technical Limits
The planning of new infrastructures needs to consider some technical limitations which are
incorporated in the design and specification of some power equipment. These technical
limitations also forms part of the regulatory and other guiding documentation imposed on the
Regulated Transmission Entity.
The PGC identifies certain minimum technical limitations that shall be adhered to during any
transmission planning study. These limits include the following:
Voltage limits;
Transmission line rating;
Transformer loading;
Other specific power equipment ratings as per design for a specific application; and
System stability limits.
Normal capacity ratings and voltage limits represent equipment limits that can be sustained
indefinitely without increased risk of equipment failure. Emergency capacity ratings and
voltage limits represent equipment operating conditions that can be tolerated for a relatively
16 One example of a supplementary action could be the application of any special protection scheme such as load shedding or
specialized inter-tripping scheme to safe guard the power system during contingencies.
Draft as of March 2012 22

short period, recognizing that there may be a small increase in the risk of failure or danger to
personnel.
The steady state power flow studies consisting of load flow analysis which models the grid
topology including the loading at the different substations is used to investigate system
adequacy in terms of satisfying capacity ratings and voltage limits.
The dynamic (time-domain) model represents the dynamic behavior of the grid over time. This
model is used to evaluate system stability under specific fault conditions. The main purpose of
the dynamic model is to study the behavior of all dynamic components of the transmission
system such as generation facilities.
Voltage Limits
Maintaining grid voltages within the specified limits is required in order for customer and
system equipment to function properly thus enhancing the life of equipment. If not managed
properly, voltage control also affects system reliability by resulting to system losses. Moreover,
it limits the ability to move power thus worsening congestion. The voltage limits set out below
that should be adhered to are based on a system healthy condition and for the conditions
following an N-1 contingency. All limits are similar to those set in the PGC.
1. System Healthy Conditions
Steady-state voltage range: +/- 5% of nominal for all voltages levels.
2. N-1 Contingencies
Steady-state voltage range: +/- 5% of nominal for all voltage levels
Voltage limit violations shall be remedied by any of the following methods:
a) by Megavolt Ampere Reactive (MVAr) dispatch of generation facilities within
the range prescribed in the PGC (0.85 power factor lagging and 0.9 power
factor leading). The ideal operating point for a generation facility is 1.0 power
factor during system healthy conditions;
b) by the appropriate transformer tap changing. In line with this, on-load tap
changing mechanism has become common additions in the world when
procuring a power transformer;
c) capacitor or reactor switching. It is recommended that capacitors and
reactors are installed at strategic locations in the grid; and
d) to improve the power factor at point of coupling to DUs or large customers,
which should typically be better than 0.95.
Transmission Line Rating
The specific assessment to be used for any new development or upgrading of the
transmission system must comply with the following criteria for transmission line ratings:
1. System Healthy Conditions
Draft as of March 2012 23

During system healthy conditions no interconnected line is allowed to exceed the
normal continuous (thermal) limit of the line. This is the 75ºC thermal rating of the
transmission line.
2. N-1 Contingencies
During a single contingency or N-1 condition, no interconnected line is allowed to
exceed the emergency thermal limit of the line for a maximum period of 2 (two) hours.
The thermal ratings are a function of the design and construction of the transmission
line. The rating of the terminal equipment should be taken into consideration. It is
possible that the terminal equipment of a specific line could be lower than the
emergency rating of the conductor and this will then act as the emergency rating of the
transmission line. It is advisable for the Regulated Transmission Entity to identify
these limiting conditions and replace the terminal equipment to increase the
emergency rating of the line to be equal to the conductor limit or 90ºC thermal rating of
the transmission line.
The Regulated Transmission Entity normally considers only the 75ºC thermal rating of
the transmission lines during system planning studies and not the 90ºC thermal rating
of the transmission line because such thermal rating of the transmission line should be
used for operational purposes only.
Loading of Transformers
The specific assessment to be used for any new development or upgrading of the
transmission system, must comply with the following criteria for transformer loading:
1. System Healthy Conditions
During system healthy conditions no transformer is allowed to exceed the nameplate
continuous Megavolt Ampere (MVA) rating of the transformer. This is typically the
100% nameplate rating of the transformer in MVA.
2. N-1 Contingencies
During a single contingency or N-1 condition, no transformer is allowed to exceed the
nameplate continuous MVA rating of the transformer. This is typically the 100% of the
nameplate rating of the transformer in MVA.
The overloading of transformers is only for system operations and not for the purpose
of grid planning specifically in the consideration for system planning studies.
Series Capacitor Banks
The series capacitor bank must be designed in line with IEC standards. The IEC standard
specifies the following design criteria and any new development or upgrading of the
transmission system must be compliant to these criteria:
8 hours in a 12-hour period: 1.1 times rated current;
½ hour in a 6 hour period: 1.35 times rated current; and
10 minutes in a 2 hour period: 1.5 times rated current.
Draft as of March 2012 24

Shunt Capacitors or Shunt Reactors
The use of shunt capacitor banks or shunt reactors for voltage control must be sized in such a
way that it does not cause a voltage change of more than three percent (3%) during system
healthy conditions when it is active in the transmission system. Furthermore, in an N-1
contingency scenario, the voltage change must not exceed five percent (5%) when it is active
in the transmission system.
Power Circuit Breakers
Newly-commissioned power circuit breakers (PCBs) should be selected with somewhat high
interrupting capacities, potentially more than the initial fault level in the area. This is to avoid
frequent replacement every time there are new generation facilities nearby or new
transmission lines terminated at the station that contributes to higher fault level. The
Regulated Transmission Entity shall standardize on PCB sizes which will be a good strategic
method to minimize the number of spares that will be required.
The following is the limits specified for PCBs and shall not be exceeded:
Single-phase breaking current: 1.15 times 3 phase fault current
Peak breaking current: 2.55 times 3 phase root-mean-square (RMS) fault
current
Tap Changer
In order to determine whether capacitors are required to correct any voltage violations, all
transformers equipped with on-load tap changers should be adjusted to nominal rating. The
full range of the transformer taps should be available for the use of the system operator in
order to control the system voltages.
Voltage Control and Reactive Power Support
The Regulated Transmission Entity is not encouraged to use the reactive power capability of
generation facilities or the transformer tapping range to control system voltages in planning
studies. The use of shunt capacitors and shunt reactors should be considered to ensure
voltage limits are complied with during system healthy and contingency operation of the
transmission system.
The use of series compensation could be considered to increase voltage levels in long radial
networks. Static VAr compensators (SVCs) should be considered to provide dynamic voltage
control during system contingencies. The SVC’s reactive capability should, however, not be
used during steady state operating conditions.
The reactive power capability of generation facilities and the tapping of transmission
transformers should only be used during N-1 contingencies and emergency situations and
should be viewed as operational supporting mechanisms rather than planning solutions.
For reactors the following planning criteria should be adhered to:
The size of switched reactors should be restricted to limit the change in system
voltage when any one unit is switched in or out of service. The voltage change should
not exceed three percent (3%) of the nominal voltage during system healthy condition
or five percent (5%) of the nominal voltage during single contingencies;
Draft as of March 2012 25

During minimum load and any one reactor out of service, the maximum continuous
system voltage should not be exceeded;
During minimum load and any one reactor out of service, the maximum reactive
power absorption capability of no generator unit may be exceeded; and
The steady state voltage at the line open end, resulting from energizing or tripping of a
transmission line circuit breaker during normal operating conditions, should not
exceed the maximum continuous system voltage.
System Stability Limits
It is the objective of system stability simulations to analyze the stability of the transmission
system in a given time period. Consistent with Section 4.4.9.3 of the PGC, the maximum
clearing time per voltage level that shall be used for simulations in relation to grid planning
shall be as per the limits below. This is further explained in Section 4.7 of this guideline.
85 milliseconds (ms) for 500 kilovolt;
100 ms for 230 kV and 138 kV; and
120 ms for voltages less than 138 kV.
3.3.3 Power Factor Considerations
The power factor of the load has a major impact on the transmission system as it affects the
voltage profile and transmission losses. A bad power factor 17 requires a high amount of
reactive power from the system. The Regulated Transmission Entity must either install
reactive devices to supply the MVAr’s for the load or buy reactive energy from the generation
facilities connected to the grid. The process of buying reactive energy is currently via Ancillary
Services Procurement Agreements between the Regulated Transmission Entity and interested
and qualified generation facilities; however, in the future ancillary services may already be
traded in the WESM. Even though, at this stage, power factor correction methods will be to a
certain extent an expensive exercise for the Regulated Transmission Entity, improving the
power factor at the loads will decrease the system losses and have a direct impact on
operating cost.
It is recommended that the Regulated Transmission Entity encourages the DUs and other
large customers to improve their power factor at the point of common coupling to values of
around 0.95 which is a typical practice in other jurisdictions.
Currently, the Regulated Transmission Entity utilizes the load power factors based on the
actual average power factor from the billing information of customers for purposes of
undertaking simulations.
3.3.4 Minimum and Peak Load Demand Considerations
The Regulated Transmission Entity has indicated that the minimum load demand in Luzon is
assumed to be 45% of the peak demand while for Visayas and Mindanao it is 60%. These
ratios according to the Regulated Transmission Entity are based from historical data, which
are then used to study the over-voltages during off-peak periods.
17 A bad power factor is typically anything less than 0.95.
Draft as of March 2012 26

3.3.5 Planning for Disposal of Assets
At the end of the useful life of equipment, the Regulated Transmission Entity should undertake
a condition assessment in order to determine whether the equipment is required to be
replaced. It should be noted that assets should only be disposed when they can no longer be
economically justified and not because it has already reached the end of its useful life. In the
event that assets have already been identified for disposal based on the result of the condition
assessment, then such assets should be considered for replacement. It should however be
noted that such projects, even if it is considered as a replacement project only, should still be
evaluated and documented in accordance with this guideline.
3.3.6 Planning for Generation
Power Plant location
It would be an ideal solution if the generation facilities could be located as close as possible to
the load which is in many cases is unattainable due to physical constraints or the specific
interest of investors. It is however recommended for the Regulated Transmission Entity to
make available the sites where incoming generation facilities can connect which entails
minimal transmission system reinforcement. In cases when the generation facility has already
decided on a location, the Regulated Transmission Entity’s participation shall be in the
integration studies.
Embedded Generation
New embedded generation facilities will have an impact on the quality of supply, the fault
levels and stability of the grid and eventually on the operation, voltage control and operating
reserves. Thus, it is encouraged that embedded generation integration studies shall be a joint
effort among the relevant DU or large customer and the Regulated Transmission Entity.
Draft as of March 2012 27

4. TECHNICAL STUDIES
4.1 INTRODUCTION
This section provides guidelines for the different applicable studies that are required to be
performed as part of developing a transmission system plan. This guideline is established
specifically for developing a plan that will assist the Regulated Transmission Entity in the
regulatory reset process but is also foreseen to aid in the development of the TDP. The
applicable studies described in this section include load flows (steady state analysis), transient
stability, voltage stability, small signal analysis, quality of supply, frequency stability and
switching studies.
4.2 DATA REQUIREMENT
Any technical study requires information describing assets to various levels of technical detail.
Below is a list of required data that shall be used in performing the required technical studies.
The following data requirement is also consistent with the requirements set in the PGC.
Historical energy and load demand data
Forecasted energy and load demand data
Generator unit data
o
o
o
o
o
o
o
o
o
o
o
o
De-rated capacity (in Megawatt (MW));
Additional capacity (in MW) obtainable from generating units in excess of net
declared capability;
Minimum stable loading (in MW);
Reactive power capability curve;
Stator armature resistance;
Direct axis synchronous, transient, and sub-transient reactances;
Quadrature axis synchronous, transient, and sub-transient reactances;
Direct axis transient and sub-transient time constants;
Quadrature axis transient and sub-transient time constants;
Turbine and generating unit inertia constant (in MW sec/MVA);
Rated field current (in Ampere (A)) at rated MW and MVAr output and at rated
terminal voltage; and
Short circuit and open circuit characteristic curves.
The following information for step-up transformers is required for each generating unit:
o
o
Rated MVA;
Rated Frequency (in Hertz (Hz));
Draft as of March 2012 28

o
o
o
o
o
o
o
o
Rated voltage (in kV);
Voltage ratio;
Positive sequence reactance (maximum, minimum, and nominal tap);
Positive sequence resistance (maximum, minimum, and nominal tap);
Zero sequence reactance;
Tap changer range;
Tap changer step size; and
Tap changer type (on load or off circuit).
The following excitation control system parameters is required for each generating
unit:
o
o
o
o
o
o
o
o
o
Direct current (DC) gain of excitation loop;
Rated field voltage;
Maximum field voltage;
Minimum field voltage;
Maximum rate of change of field voltage (rising);
Maximum rate of change of field voltage (falling);
Details of excitation loop described in diagram form showing transfer
functions of individual elements;
Dynamic characteristics of over-excitation limiter; and
Dynamic characteristics of under-excitation limiter.
The following speed-governing system parameters is required for each reheat steam
generating unit:
o
o
o
o
o
o
o
o
High pressure governor average gain (in MW/Hz);
Speeder motor setting range;
Speed droop characteristic curve;
High pressure governor valve time constant;
High pressure governor valve opening limits;
High pressure governor valve rate limits;
Re-heater time constant (active energy stored in re-heater);
Intermediate pressure governor average gain (in MW/Hz);
Draft as of March 2012 29

o
o
o
o
o
o
Intermediate pressure governor setting range;
Intermediate pressure governor valve time constant;
Intermediate pressure governor valve opening limits;
Intermediate pressure governor valve rate limits;
Intermediate pressure governor loop; and
A governor block diagram showing the transfer functions of individual
elements.
The following speed-governing system parameters is required for each non-reheat
steam, gas turbine, geothermal, and hydro generating unit:
o
o
o
o
o
o
o
Governor average gain;
Speeder motor setting range;
Speed droop characteristic curve;
Time constant of steam or fuel governor valve or water column inertia;
Governor valve opening limits;
Governor valve rate limits; and
Time constant of turbine.
The following plant flexibility performance data is required for each generation facility:
o
o
o
o
o
o
Rate of loading following weekend shutdown (generating unit and generation
facility);
Rate of loading following an overnight shutdown (generating unit and
generation facility);
Block load following synchronizing;
Rate of load reduction from normal rated MW;
Regulating range; and
Load rejection capability while still synchronized and able to supply load.
The following auxiliary load demand data is required:
o
o
Normal unit-supplied auxiliary load for each generating unit at rated MW
output; and
Each generation facility auxiliary load where the station auxiliary load is
supplied from the grid.
General grid data required:
Draft as of March 2012 30

o
The electrical diagrams and drawings are required to indicate the quantities,
ratings, and operating parameters of the following:
• Equipment (e.g., generating units, power transformers, and circuit
breakers);
• Electrical circuits (e.g., overhead lines and underground cables);
• Substation bus arrangements;
• Grounding arrangements;
• Phasing arrangements; and
• Switching facilities.
o
The following circuit parameters are required:
• Rated and operating voltage (in kV);
• Positive sequence resistance and reactance (in ohm);
• Positive sequence shunt susceptance (Siemens or ohm-1);
• Zero sequence resistance and reactance (ohm); and
• Zero sequence susceptance (Siemens or ohm-1).
o
The following data is required for a step-up and power transformers:
• Rated MVA;
• Rated voltages (kV);
• Winding arrangement;
• Positive sequence resistance and reactance (at max, min, and
nominal tap);
• Zero sequence reactance for three-legged core type transformer;
• Tap changer range, step size and type (on-load or off-load); and
• Basic lightning impulse insulation level (in kV).
o
The following information is required for the switchgear, including circuit
breakers, load break switches, and disconnect switches:
• Rated voltage (in kV);
• Rated current (in A);
• Rated symmetrical RMS short-circuit current (in kA); and
• Basic lightning impulse insulation level (in kV).
Draft as of March 2012 31

o
The following data on independently-switched reactive power compensation
equipment is required:
• Rated capacity (in MVAr);
• Rated voltage (in kV);
• Type (e.g., shunt inductor, shunt capacitor, SVC); and
• Operation and control details (e.g. fixed or variable, automatic, or
manual).
o
The following data is required if a customer’s load demand may be supplied
from alternative connection point(s):
• The alternative connection point(s);
• The demand normally supplied from each alternative connection
point;
• The demand which may be transferred from or to each alternative
connection point; and
• The control (e.g., manual or automatic) arrangements for transfer
including the time required to affect the transfer for forced outage and
planned maintenance conditions.
The data requirement specified in Section 4.2 is required, where relevant, if a distribution
system (or other customer or end-user system) has embedded generation facilities and
significantly large motors. The short circuit contribution of the embedded generating units and
the large motors at the connection point shall be provided by the DU (or the other customer or
end-user). The short circuit current shall be calculated in accordance with the IEC Standards
or any equivalent national standards.
4.3 LOAD FLOW STUDIES
Load flow studies are typically conducted using a computer simulation package (e.g. Power
System Simulator for Engineering (PSS/E)) with a valid study file containing the grid model.
The purpose of the study is to determine whether an existing or reinforced system can satisfy
the voltage and current limits, under steady state conditions, when the system is healthy or
when one or more components are out of service.
4.3.1 Minimum Data Requirements
To be able to compare a proper load flow scenario the following data is required at a
minimum:
Load forecast for peak and light load at each substation
Positive sequence parameters for all equipment:
o
o
Resistance;
Reactance;
Draft as of March 2012 32

o
o
o
Susceptance;
Line length; and
Rating of equipment.
Generation patterns and constraints
4.3.2 Criteria and Study Scenarios
Load flow studies should be conducted for the following network conditions:
a) annual peak load, typical generation pattern with peaking plant in generation mode;
and
b) light load scenario (the minimum load given by the load forecast) and generation
scaled down to light load scenarios.
The grid should be studied for healthy conditions and for N-1 contingencies. N-2 or greater
contingencies (including generation contingencies) will only be investigated when it is
considered likely that a valid business case will exist to justify the additional capital
expenditure to address them.
For light load conditions, the system is only studied for healthy conditions as maximum
voltages are likely to occur with all lines in service. Potentially, the only contingency condition
that could increase the voltage is the loss of a shunt reactor or the loss of load. Furthermore,
if there is shunt reactors in the system under investigation, studies must still be conducted to
ensure that no unacceptable over-voltages will occur.
Each network scenario should include a calculation of system losses which will typically form
part of the financial justification of the project.
4.3.3 Load Assumptions
Since individual loads peak at different times, the total system maximum demand at time of
system peak (TOSP) is less than the sum of the individual peak loads. To obtain realistic
generation conditions and average loading and losses in studies of the overall transmission
system, each individual peak load is scaled down by a diversity factor such that the total load
on the generation facilities matches the forecasted load for the total system. The adjusted
loads are known as diversified maximum demands.
For studies of selected areas in the system (regions or islands), individual loads should be
adjusted such that the total load in that area matches the actual or expected maximum value.
It is probable that these values will occur at a time different from the TOSP.
For studies where the supply to only one specific load point or customer is being investigated,
the actual undiversified peak value of this load or substation should be used.
For light loading scenarios the minimum load must be based on historical data for each grid,
e.g.:
Luzon
Visayas
– 45% of system peak
– 60% of system peak
Draft as of March 2012 33

Mindanao
– 60% of system peak
4.3.4 Generation Assumptions
The Regulated Transmission Entity is currently undertaking studies using the dispatch
scenarios for Luzon, Visayas and Mindanao as set out below. These have been reviewed and
assessed to be acceptable and is therefore recommended to be used in the conduct of load
flow studies.
Luzon
The following generation dispatch conditions shall be used:
Maximum North-Wet (all generation facility outputs in the northern part of the grid are
set to their maximum capacities)
Maximum South-Dry (all generation facility outputs in the southern part of the grid are
set to their maximum capacities)
Typical scenario (generation facility outputs are based on the typical output levels of
plants during system peak load).
The above scenarios shall ensure that regardless of dispatch combination, the N-1
compliance of the grid is assessed for all possibilities. Additional scenarios are also currently
being considered by the Regulated Transmission Entity for particular study areas where
varying dispatch output of associated generation facilities could result in additional
transmission system constraints.
Visayas
The following generation dispatch conditions shall be used:
Maximum Leyte Scenario (the geothermal generation facilities in Leyte are maximized
while the generation facilities in Panay serve as regulating plants; the power plants in
Cebu, Negros and Bohol are maximized)
Maximum Panay Scenario (the generation facilities in Panay are maximized while the
geothermal generation facilities in Leyte serve as regulating plants; the generation
facilities in Cebu, Negros and Bohol are maximized).
For the Visayas dispatch scenarios above, the following general considerations shall be
observed:
Base load generation facilities are priority dispatch over peaking generation facilities.
In case base load generation facilities are already sufficient to supply the entire load
requirement of the Visayas grid, which is mostly the case upon entry of additional
generation facilities, all peaking plants are assumed to be offline;
Intermittent generation facilities are assumed either at full dispatch or offline
depending on which is the worst scenario; and
Embedded generation facilities are assumed online until the end of their bilateral
contract.
Mindanao
Draft as of March 2012 34

The generation dispatch scenario that shall be used for Mindanao is the Maximum North
Scenario. This scenario shall be used to guarantee the adequacy of transmission lines that will
deliver power to the South and Northwestern Mindanao areas during contingencies. The
assumption for the scenario is that the power, especially those coming from hydro-electric
generation facilities are maximized thereby stressing the highest loading to the transmission
lines that supply power to the load centers i.e. Davao and General Santos.
4.4 SHORT CIRCUIT STUDIES
Fault level studies should be done for a number of reasons as listed below:
Any new planned grid reinforcement requires a fault level analysis to determine if fault
level values are going to exceed the ratings of existing equipment such as circuit
breakers, current transformers (CTs), or other switchgear and busbars;
For relevant new assets, appropriate fault ratings are determined by fault level studies
which should consider planned projects including generation which may have an
impact on the fault level in future. This is to ensure that new equipment is not required
to be replaced due to rising fault level increases in the short term;
Studies for the connection of new voltage waveform distorting load (e.g. arc furnaces,
mine winders, etc.) or switching of large motors require that the minimum credible
fault level is determined;
Fault level studies should be performed as an input to calculating protection settings.
This is to ensure that protection relays operate correctly in response to faults;
Fault level studies should be performed for high voltage direct current (HVDC)
termination points in the network to determine the relative maximum size of a
converter station when conventional HVDC is considered; and
Fault level studies should be performed to determine the maximum size of shunt
devices at a specific location.
Overview studies of fault levels throughout the system only require the calculation of three (3)
phase fault levels (using only the positive sequence network). Generation facilities should be
represented by a voltage of 1 per unit (pu) behind a saturated sub-transient reactance and all
transformers by their reactances on nominal tap. The Regulated Transmission Entity shall
consider the scenario of “all generation facilities online” to get the most conservative values.
When higher accuracy is required, fault studies should follow a load flow study in which the
magnitude and angle of the generation facility voltages behind transient reactances are
derived and the appropriate tap positions and reactances of the various transformers are
calculated. To determine maximum possible fault levels, all existing generation facilities (even
small generation units) should be in service and active.
Single phase fault analysis requires setting up the negative and zero sequence parameters in
addition to the positive sequence parameters in the PSS/E model. Furthermore, the
grounding setup for transformers needs to be accurately modeled. It is noted that, if
transformers are solidly earthed a single phase fault level can exceed three (3) phase levels in
certain scenarios.
Draft as of March 2012 35

Circuit breakers that exceed rupturing capacity 18 and other assets for which technical
limitations have been breached should be replaced to avoid risk of damage to assets and
personnel. As an interim solution, or permanent solution at the expense of operational
flexibility, the assets which were identified to be replaced could be operated by reducing fault
in-feeds 19 instead of replacing these assets. This reduction in fault in-feeds can be done by
splitting busbars, adding fault limiting reactors, or bypassing the over-stressed bus with certain
lines. It is important to note that the above solution is an operational solution and not a
planning solution and the solution is therefore not viewed as a medium to longer term solution
when planning the network.
Fault level revisions should be communicated to customers whenever an expansion plan is
expected to have a significant impact on fault levels. Communicating to customers in a timely
manner will allow customers the opportunity to take necessary action to ensure their
equipment can withstand the revised fault levels.
To determine the minimum credible fault level at a particular point of the transmission system,
a fault level study is performed with a load flow solution including the most onerous
contingency (N-1) or as appropriate. The values obtained is used to determine if a large motor
can be started; or if additional reinforcement is required to raise the fault level sufficiently to
start the motor; or the customer could be advised that a soft motor starting system should be
installed. In general, this is more of a consideration for DUs than the Regulated Transmission
Entity, unless a customer is connected directly to the grid.
4.5 SWITCHING STUDIES
Load flow studies are typically used to calculate the initial and final steady state voltages when
lines, capacitors, reactors or loads are switched. On the other hand, switching studies
contribute to the decision making of the size and location of equipment such as capacitors and
reactors. Line reactors are tested to ensure that transmission lines can be energized without
exceeding voltage limits when a reactor is in service. These studies should be conducted to
ensure that the voltage change is less than three percent (3%) when switching shunt
capacitors in and out or when switching interruptible loads. A typical value of 5% can be used
during single contingencies in the network.
For switching studies, variable MVAr devices are allowed to operate normally, but transformer
taps are fixed and no switching of shunt capacitors or reactors is allowed.
Dynamic switching studies, to determine instantaneous voltages after a switching operation
may be required for insulation coordination. These studies require the use of dynamic
programs (travelling wave, electro-magnetic transient programs etc.) and are generally the
responsibility of the generation facilities (however, the Regulated Transmission Entity may
participate in such studies).
4.6 VOLTAGE STABILITY
Voltage stability refers to the ability of a system to maintain steady voltages at all buses in the
system, from a given initial operating condition, after being subjected to a fault or disturbance.
Voltage stability depends on the ability of the system to maintain equilibrium between load
supply and load demand. Voltage instability occurs in the form of a progressive rise or fall of
18 Rupturing capacity or breaking capacity expresses the current that a circuit breaker is capable of breaking at a given
recovery voltage under certain set conditions of operation.
19 Fault in-feeds refer to fault current flowing into the transmission system linked directly to an asset or assets.
Draft as of March 2012 36

voltages of some buses and may lead to the loss of load in an area, tripping of transmission
lines and other elements by their protection circuits. These outages may lead to more
outages that in turn may lead to loss of synchronism or activation of the under field current
limit protection of some generation facilities.
At transmission voltages (higher voltages), the voltage drop at the receiving end is mainly
caused by the flow of reactive power through the reactance of the transmission system. The
reactive power flow in the system will be reduced if reactive power is supplied at the receiving
end. This is typically achieved by means of e.g. shunt capacitors, SVCs, generation facilities,
synchronous condensers or some flexible AC transmission system (FACTS) devices.
Generation facilities, synchronous condensers and SVCs are variable reactive power or MVAr
sources and could be used to supply reactive power and to keep the voltage more constant.
The maximum angle, as measured between two directly connected substations, should
preferably not exceed 45 o or 50 o .
The voltage stability limit can be established for any given system by carrying out load flow
studies with progressively increased loads until the load flow fails to converge 20 . The power
flow just before the point of non-convergence is assumed to be the maximum power that can
be supplied before the voltage collapses. It would be impractical to attempt to operate the
system at this point since small load variations are bound to occur. In practice, the maximum
power transfer should be restricted to a value of typically ten percent (10%) below the
maximum value (knee-point of the power voltage-curve).
The maximum power transfer is limited either by voltage collapse or by an unacceptably low
receiving end voltage as follows:
ten percent (10%) less than the power level corresponding the point of nonconvergence
as described above, or
the power which causes the receiving end voltage to reach the minimum
recommended value.
When an SVC is available in the area of study, the SVC dynamic range should not be used
completely to determine the steady state transfer capability. The maximum power transfer
should be limited to the point before the SVC starts to operate outside its normal steady state
position.
The Regulated Transmission Entity should look at the following equipment to improve the
voltage collapse limit of the transmission system:
Shunt capacitor banks to improve receiving end voltages;
Series capacitor banks to reduce line impedance and effectively increase receiving
end voltages. Series capacitor banks also increase the Surge impedance loading
(SIL) of a transmission line; and
Transmission lines as a more expensive solution to reduce system impedance.
20 “Being able to converge” is the term used to explain that the load flow software found a numeric solution to the network model
which indicates that the solution modelled appear viable from a numeric perspective. “Fails to converge” is the term used to
explain that the load flow software did not find a numeric solution to the network model which indicates that the solution
modelled appear not to be viable from a numeric perspective.
Draft as of March 2012 37

4.7 TRANSIENT STABILITY
The grid relies on synchronous machines for generation of electrical power and a necessary
condition for satisfactory system operation is that all synchronous machines remain in
synchronism. Transient stability is the ability of the system to maintain synchronism when
subjected to a severe fault or disturbance, such as a short circuit on a transmission line. The
resulting system response involves large excursions (oscillating or alternating motion away
from a point of equilibrium) of generator rotor angles and is influenced by the nonlinear powerangle
relationship. Transient stability in this regard relates to first swing stability of the
transmission system.
4.7.1 Minimum Data Requirements
The following data is required to perform transient stability analysis:
Load flow case file representing the pre-fault state of the system;
Dynamics data file representing the dynamic behavior of each dynamic component;
and
Sequence of events.
The following items must be included in the dynamics data file to perform transient stability
simulations as the equipment’s dynamic behavior may influence the results:
Generation facilities;
Excitation systems;
Power system stabilizers (PSS);
Governors;
Loads; and
SVCs or HVDC or synchronous condensers (SCOs) or FACTS devices.
4.7.2 Criteria
Study scenarios
The characteristics of the transmission system should be such as to maintain stability
following:
A three phase line or busbar fault, cleared in normal protection times, with the system
healthy and the most onerous system loading condition;
A single phase fault cleared in “bus trip times” 21 , with the system healthy and the most
onerous system loading condition; and
21 Bus trip time is the time that the bus zone protection will take to strip a busbar when required due to a specific fault condition
and will differ from substation to substation.
Draft as of March 2012 38

A single phase fault cleared in normal protection times, with any one line out of
service and the generation facility loaded to average output.
Fault Clearing Times
The fault clearing time is defined as the time it takes for the protection equipment to clear or
remove the fault from the power system to allow normal operation to proceed. Typical fault
clearing times for the protection installed in the power system are as per the table below:
Table 1: Typical Clearing Times
Note:
TYPE OF FAULT 500kV 138 kV - 230kV

Faults that change the topology of the transmission system, change the system reactance and
alter the power-angle relationships of generation facilities shall be applied. These faults are
considered to have the most onerous impact on system stability and are specified as follows:
A three-phase zero impedance line-end fault cleared by tripping the faulted line;
A three-phase busbar fault cleared by tripping the relevant outlets from the associated
busbar;
Loss of generation;
Loss of major load; and
Loss of tie-lines.
As a note, three-phase faults are considered to have the most onerous impact on the system
from a transient stability point of view compared with that of a single phase faults.
Output Parameters
The following output parameters are not specific to transient stability results and contain
typical output parameters for any kind of stability study. The analysis of the output channels
(or variables that provide the resulting values from the study) allows the Regulated
Transmission Entity to differentiate between the different stability phenomena. The following
outputs are useful when interpreting the outcome of any stability analysis and can typically be
plotted relative to time.
Relative Rotor Angle and Speed: This information is used to determine whether the
machines(s) would remain in synchronism or not (pole-slip) following a fault. These
plots provide an indication of how the machines in an area are oscillating with respect
to each other. The rotor angle variable output is used in assessing the magnitude and
duration of post-fault power system oscillations.
Generation Real Power: The real power variable output is used to determine whether
or not the power output of the generating unit is less than zero which would indicate
that the generating unit acts as a motor. In this event, the inverse power relay settings
should be examined to determine whether this would result in unit tripping. Typically,
an indication of oscillation frequencies and system damping can also be obtained from
these variable outputs.
Generation Reactive Power: The generation reactive power variable output is used
to determine whether or not the reactive power output will be sufficiently damped and
return within the continuous rating of the machine. Insufficient steady state voltage
support exists if the reactive power fails to recover within the continuous rating.
Bus Voltage: Variable output for bus voltages provide information on whether
machines remain in synchronism or not. The bus voltage variable output is useful in
assessing the magnitude and duration of post-fault voltage dips and peak-to-peak
voltage oscillations. Furthermore, these variable outputs provide an indication of
system damping and the level to which voltages are expected to return to its steady
state value.
Draft as of March 2012 40

Bus Frequency: The bus frequency variable output provides the magnitude and
duration of the post-fault frequency decline or increase in the transmission system,
especially during loss of load or generation.
Line Flows: The line flow variable output provides information on the magnitude of
the post-fault active and reactive power swings on transmission lines. Furthermore, it
provides information on transient power exchange and the occurrence of possible outof-step
conditions between two grids or islands. As a note, when large power
reversals occur on transmission lines, out-of-step conditions may be evident.
Accelerating Power: The accelerating power variable output provides information
regarding the dynamic response of the prime mover system (turbine and governor
control system) of the machine. It also provides information on whether the machine
would remain in synchronism or not following a fault.
Generator Field Voltage: The generator field voltage variable output provides
information on the dynamic response of the excitation system of the machine.
Furthermore, these variables could be used to assess the reaction of the automatic
voltage regulator (AVR) and to determine if the AVR is in any way causing the
machine to lose synchronism.
PSS Output: The PSS variable output provides information on how well the PSS is
responding to the oscillatory deviations of the specific machine in relation to the rest of
the transmission system. Furthermore, it can also provide information in determining if
the PSS is contributing to the instability of the machine in relation to other machines in
the generation facility or to other units in the system.
Apparent Impedance: The transmission line apparent impedance variable output
provides information on whether the apparent swing locus will enter the tripping
zones(s) of the out-of-step or distance relays.
Voltage behind Transient Reactance (E’q): The E’q variable output provides
information on whether a machine is losing synchronism. During stable operation, the
E’q variable output over time will be an approximate straight line with a zero slope. In
the event that the machine loses synchronism, the E’q plot will typically be a straight
line with a positive slope.
Critical clearing time
The critical clearing time relates to the longest fault duration period that the system can
withstand before losing synchronism. The critical clearing time can be determined by
increasing the clearing time for the fault in appropriate steps until the system goes unstable.
The critical clearing time can be useful in determining protection settings and to determine the
correct type of circuit breaker, e.g. two- or three-cycle breaker.
4.7.4 Results
The results for the transient stability study should be screened for any of the issues related to
the criteria for transient stability referred to in Section 4.4.9.3 of the PGC which is also
discussed in Section 3.3.2 of this guideline.
As a guide, typically the following factors have a large influence on the evaluation of the
transmission system:
Draft as of March 2012 41

The generation loading;
The generation output during the fault;
The fault clearing time;
The post-fault transmission reactance;
The generation reactance;
The generation inertia;
The generation internal voltage magnitude; and
The transmission bus voltage magnitude.
4.7.5 Transient Instability
Transient instability is a serious condition in any system which could lead to a partial or full
system black out condition. The Regulated Transmission Entity should consider the following
mitigation factors when transient instability is encountered or envisage for any system
condition:
Reduction of the impact experienced during any fault or disturbance by decreasing the
severity of a fault through decreasing the fault duration. This can be done by installing
faster protection systems;
Reduction of the accelerating torque through the control of prime mover mechanical
power; and
Reduction of the accelerating torque by applying artificial load, such as a braking
resistor.
Further to mitigating transient instability, there are a few options that could be applied to
enhance the transient stability of a system as listed below:
Build more transmission lines;
Application of braking resistors;
Increase inertia of new generating units;
High speed fault clearing;
Application of FACTs devices;
Reactor switching;
Single pole switching;
Steam turbine fast valving;
Generation tripping to house load; and
High speed excitation systems.
Draft as of March 2012 42

4.8 SMALL SIGNAL STABILITY
Small signal stability is the ability of the system to maintain synchronism when subjected to
small faults or disturbances 22 . This condition is typical of a grid with insufficient damping of
power oscillations that are created due to the small fault. The following types of power
oscillations exist:
Local modes or machine-system modes are associated with the oscillating of the
units at a generation facility with each other and with respect to the rest of the
transmission system. The term ‘local’ is used because the oscillations are typically
found to be localized at one generation facility or in small parts of the transmission
system.
Inter-area modes are associated with the swinging of many machines in one part of
the system against machines in other parts of the transmission system. These are
caused by two or more groups of closely coupled machines being interconnected by
weak ties.
Control modes are associated with generating units and other control related
equipment. Poorly tuned exciters, speed governors, HVDC converters and SVCs are
the usual causes of instability of these modes.
Torsional modes are associated with the rotational components of the turbinegenerator
shaft system. Instability of these modes may be caused by interaction with
excitation controls, speed governors, HVDC controls, and series-capacitor
compensated lines.
4.8.1 Minimum Data Requirements
Signal stability analysis requires the following data:
Load flow base case;
Dynamic input file; and
Unique computer code to model equipment not included as part of the simulation
program used.
4.8.2 Criteria
Local mode oscillations identified should have a minimum damping of 10%. Post fault
damping criteria for contingency studies may be reduced by 50%.
Inter-area mode oscillations identified should have a minimum damping of 5%. Post
fault damping criteria for contingency studies may be reduced by 50%.
Control mode oscillations identified should have a minimum damping of 20%.
Voltage Recovery
22
A small fault/disturbance can be defined as the switching of load or reactive shunt devices on the power system.
Draft as of March 2012 43

The voltage should recover to 90% of its pre fault value within two (2) seconds after the fault
occurred and should be applied at all load demand levels. As a note, the above value is set to
avoid fast voltage collapse due to stalling of induction machines.
Frequency Drop
Any frequency drop should not result in load shedding for loss of any single generating unit.
Damping
Damping should be such that the machine rotor angle or speed deviations are less than 7.5%
of initial peak values after 10 seconds following a fault on the transmission system.
Pole Slip
Most new generating units have pole slip protection installed as a default to protect the
generation facility. A safe margin to assume as the maximum allowable rotor angle would be
120.
4.8.3 Methodology
The following methodology shall be applied for small signal stability studies:
Develop appropriate network base case;
Develop a list of credible contingencies;
Perform an eigenvalue scan to identify bad or suspicious data;
Set up an initial small signal stability minimum damping criteria for local and inter-area
modes;
Perform pre-contingency eigenvalue scans on the base cases in order to:
o
o
Classify the types of oscillatory modes in terms of local, inter-area and control
modes
Identify the troublesome modes on the system i.e. oscillatory modes which do
not meet the minimum damping criteria;
Perform detailed eigenvalue analysis (eigenvectors, participation factors, and
frequency responses) on the modes identified above;
Verify the existence of the oscillatory mode by performing non-linear time domain
studies at different operating conditions;
Determine the cause of insufficient damping and correct the problem via:
o
o
o
o
Correcting bad or suspicious data
Determining generation or transmission transfer limits
Tuning of existing controllers, e.g., exciters, governors, PSSs, HVDC, SVCs
Adding supplementary controllers such as PSS
Draft as of March 2012 44

o
Adding additional transmission equipment, e.g. lines or FACTS devices;
Verify the improvement in damping by running non-linear time domain studies for the
solutions identified above; and
Repeat analysis for the post-contingency cases based on the credible contingency
list.
4.8.4 Results
The results are generally analyzed in two separate domains as follow:
Frequency domain where the system eigenvalues, eigenvectors, damping and
participation factors are analyzed; and
Time domain where standard time domain plots from a transient stability simulation
are analyzed.
The frequency of a mode of oscillation in a transmission system is dependent on the following:
System strength that is the number, size and loading of transmission lines. As a note,
typically the stronger the system the higher the natural frequency;
Generation inertia, based on its size and geometry. As a note, typically the larger the
inertia the lower the natural frequency; and
Generation power output because the loading of the generation facility can be related
to its rotor angle. Typically as the load increases the angle increases, and the higher
the angle the lower the natural frequency.
The following classifications of the various oscillation modes are also possible:
Local Problems
o
o
Local plant modes: where a single generation facility or plant oscillates
against the rest of the system (from 0.7 Hz to 2Hz).
Interplant or machine modes: where generation facilities close to each other
oscillate against each other. The frequencies of the modes can be up to 3 Hz.
Global Problems
o
o
Inter-area modes: where a group of generation facilities in one area oscillate
against a group of generation facilities in another area and where the system
is clearly split via an interconnection. The frequencies range from 0.1 Hz to
0.3 Hz.
Intra-area modes: where sub-groups of generation facilities in an area (that is
meshed) oscillate against each other. The frequencies of the modes range
from 0.4 Hz to 0.7 Hz.
4.9 SUB-SYNCHRONOUS RESONANCE (SSR) STUDIES
In most stability studies, the rotor of the generating unit is represented as a single mass
system. In reality, the rotor is a complex mechanical structure that consists of several
Draft as of March 2012 45

predominant masses connected by shafts of finite stiffness. Under transient conditions,
torsional oscillations exist between the different mass sections of the rotor. Torsional
oscillations in the sub-synchronous range could, under certain conditions, interact with the
electrical system with adverse effects. Special problems related to torsional oscillations
include the following:
Torsional interaction with power system controls;
Sub-synchronous resonance with series compensated transmission lines; and
Torsional fatigue due to network switching.
SSR is mainly a concern for nuclear and fossil thermal power plants. Hydro units are typically
not a source of concern when considering SSR studies.
SSR studies should be conducted when new generation facilities are included into the
network, or where network changes affect generation facilities that are known to be prone to
SSR problems, or when new series capacitor banks are added to the transmission system. In
order to perform a SSR study, the following broad categories should be applied:
Data gathering;
Frequency scanning; and
Eigenvalue analysis.
This type of study is normally done by the manufacturers of the new generating units or new
series capacitor banks. However, it is important for the Regulated Transmission Entity to
understand and form a key role in these studies.
4.9.1 Minimum Data Requirements
The following data is generally required for a first-pass SSR study:
Network Data: Comprising the entire grid including proposed system upgrades and
changes. In order to reduce calculation times and computational complexity in the
eigenvalue studies, the generating units at a generation facility can be combined
(equivalence mathematical model could be developed) into a single generating unit.
Generation Torsional Data: For each applicable generating unit, the data required is
for a lumped parameter multi-inertia shaft system. The data is listed as lumped inertia
constants (units - kg.m2) and torsional stiffness’s of interconnecting shafts (units -
Nm.rad-1 x 106).
For eigenvalue studies the torsional data is required in pu with the inertias specified as
an inertia constant (H). Based on the machine ratings and a frequency base, the pu
values of the inertia constant (H) and torsional stiffness’ shall be calculated.
Torsional Frequency Data: This data is calculated from the torsional mechanical
data.
Torsional Interaction Susceptibility (TIS) Values: A useful parameter calculated
from the torsional mechanical data is the TIS which gives an indication of how
susceptible a mode is to SSR.
Draft as of March 2012 46

Dynamic controller data: Generally dynamic controllers can be omitted for an initial
study, but needs to be included when detailed studies are performed.
4.9.2 Frequency Scanning
Frequency scanning provides a broad overview of the characteristics of the network at subsynchronous
frequencies. These studies identify cases where SSR is not of concern and one
can reduce the number of cases required to be studied using eigenvalue analysis. Where
frequency scans indicate SSR is a possibility, more accurate studies (eigenvalue analysis) are
required.
The method of analysis is to look into the transmission system from a point inside the air gap
of a generation facility and calculate the network impedance seen by the generation facility.
The mechanical torsional system of the generation facility interacts with the electrical network
at frequencies called the complementary mechanical frequencies of 60Hz ± fm (where fm =
the mechanical torsional frequency). Therefore there are potential SSR occurrences where
electrical resonances identified in the frequency scan coincide with the complementary
mechanical frequencies. A match between an electrical resonance and a complimentary
mechanical frequency does not imply a definite SSR occurrence; rather it merely indicates that
the potential for SSR exists. Whether an SSR problem will occur depends on the degree of
interaction between the electrical and mechanical resonances and this should be ascertained
by eigenvalue studies.
Frequency scans must be performed for all possible grid configurations, generating patterns,
contingencies and load demand scenarios. This will enable the Regulated Transmission Entity
to determine the most onerous case for which SSR could occur.
When the frequency scan reveals network impedance below zero, the eigenvalue scans
should be performed to analyze any torsional modes that may occur in the frequency range
and the possibility of SSR to occur.
4.9.3 Eigenvalue Analysis
The method of analysis for eigenvalues is well proven and provides immediate and clear
information on the state of each generation torsional mode.
Eigenvalue analysis is usually performed using a software package that is capable of the
modeling the dynamics of transmission system voltages and currents and the multi-inertia
shaft systems of generation facilities. The modeling of both of these elements is essential for
accurate SSR studies. One limitation of modeling the grid dynamics in detail is that it can
easily increase the size of the system model and the system order can easily become too
large for the eigenvalue solving routines.
For the eigenvalue calculations, all excitation systems can be removed from the generation
dynamic models since these do not have much influence on the damping of SSR modes. The
generation facility of concern and those other generation facilities electrically close to it shall
be represented with their full detailed models, while all other generation facilities electrically
remote from the study generation facility can be represented by infinite busses. This typically
leads to less damping of the torsional modes and is suitable for a first pass calculation. If
results show a condition of instability, detailed calculations with more specific generation
facility representation is required.
Draft as of March 2012 47

The generation facility of concern shall have its mechanical damping set to zero. Once the
eigenvalues are calculated, the real parts of the eigenvalues for the mechanical modes are
due to the electrical damping contribution. A positive value for the real part of the eigenvalue
would indicate a negative damping contribution from the electrical network due to SSR and
would be a cause for concern.
Where there are cases of SSR occurrences, transient studies should be performed to confirm
the findings of the SSR studies. It is also recommended that results of SSR studies be verified
by an SSR expert.
4.10 GENERATION FACILITIES
4.10.1 Integration of Generation Facilities
The integration of a new generation facility into the grid must be in line with the requirements
as specified in the PGC. When planning the integration of new generation facility, the
succeeding criteria shall apply.
Steady State Stability
Generation facilities of less than 300 MW:
with all connecting lines in service it should be possible to transmit the total output of
the facility to the system for any load demand condition. If the local area depends on
the generation facility for voltage support, the connection must be done with a
minimum of two lines.
Generation facilities of more than 300 MW:
with one connecting line out of service it should be possible to transmit the total output
of the facility to the system for any load demand condition.
with the two most onerous line outages it shall be possible to transmit the entire
output of the generation facility less the smallest generating unit at the facility.
Generating units installed to supply station auxiliary loads, provide standby auxiliary
supply, provide black start capability, or as dedicated off-site power supply to a
nuclear power station, are excluded from the definition of smallest generating unit.
Transient Stability
Transient stability should be retained for all three (3) the following conditions:
Normal condition: A three (3) phase, line or busbar fault, cleared in normal protection
times, with the system healthy and the most onerous generation loading condition
(typical light load),
Stuck breaker condition: A single phase busbar fault, cleared in “bus strip” times (i.e.
back-up protection), with the system healthy and the most onerous generation loading
condition (typical light load),
Contingency condition: A single phase fault, cleared in normal protection times, with
any one transmission line out of service and the generation loaded to average
availability.
Draft as of March 2012 48

Small Signal Stability
Small signal stability studies are required to verify that the system remains secure and that no
new oscillations or negative influences are created on the network which poses a danger to
existing equipment. New power plant should not result in local oscillations or inter-area
oscillations.
SSR
SSR studies that are required to be conducted for new generation facilities include: in the
vicinity of known SSR issues; where series capacitors are installed near the generation facility;
where generation facilities prone to SSR are installed; and where equipment with control
systems are installed that might influence the transmission system impedance.
4.10.2 Renewable Generation
Renewable generation can comprise any generation using natural resources such as wind,
sun and free-flowing water. However, this section refers to only wind and solar generation
types.
Wind
Wind turbines can be divided into four main types as follows:
Type A is a directly connected conventional induction generator;
Type B is a wound rotor induction generator with variable rotor resistance;
Type C is a doubly-fed induction generator (DFIG); and
Type D is a full size power converter unit.
As a note, type A, B and mostly types C will require additional volt ampere reactive (VAr)
compensation, such as SVCs or static condenser or compensators (STATCOMs), to comply
with the basic operational requirements of any grid. Furthermore, types A, B and C also have
fault level implications, which could be either beneficial or not depending on the strength of the
existing system.
Solar
At present, solar technology can be divided into different types including the two types below:
1. Photovoltaic Plants
Solar Photovoltaic (PV) systems use solar cells to convert the sun’s energy directly
into an electric current. Concentrated PV (CPV) systems seek to increase the
efficiency of normal PV systems by using lenses and mirrors to concentrate sunlight
onto solar cells.
PV panels are typically connected to the grid through a power converter which
generally includes reactive and active power controls which is beneficial at any
location in the grid. One disadvantage of this technology is the variable nature of the
natural source of sunlight.
Draft as of March 2012 49

As a note, a high number of PV plants in the grid can negatively affect power quality
and reliability specifically in smaller grids (or island grids). This is due to the natural
source not being reliable.
2. Concentrated Solar Power
Concentrated Solar Power (CSP) systems use concentrated heat from the sun to
power a traditional steam turbine or engine to generate electricity. CSP technologies
are broken down into different types as listed below:
Parabolic Trough;
Central Receiver;
Compact Linear Fresnel Reflector; and
Parabolic Dish Stirling systems.
CSP is not as sensitive to the sun as compared to PV systems and could be viewed
as being a more constant source of power.
4.10.3 Minimum Data Requirements
The relevant renewable generation model is required for purposes of both load flow as well as
stability studies. Even though specific detailed models are typically available from
manufacturers, in some cases the Regulated Transmission Entity may use typical models as
available in the software libraries.
4.10.4 Type of Studies
The Regulated Transmission Entity needs to conduct the same type of studies as required for
any generation integration plan, i.e. load flow and stability studies. Where relevant, the
Regulated Transmission Entity should consider energy storage devices when CSP is studied.
4.11 QUALITY OF SUPPLY STUDIES
When performing studies in relation to supply quality, it is important to note that from the onset
of the study the grid already have some harmonics, unbalance and flicker. Any new load
demand or system change could disturb the existing pattern and cause unacceptable levels of
quality of supply. Therefore, it is important to know the levels of unbalance, harmonics and
flicker throughout the transmission system prior to simulating the effects from additional load
demand or system changes.
4.11.1 Unbalance Studies
Unbalance studies are generally not necessary in systems with high fault levels, as the
unbalance due to loads or transmission lines is typically unlikely to be large enough to be a
cause for concern. However, system voltages at the point of utilization can be unbalanced for
several reasons as listed below:
The uneven distribution of single-phase loads;
Unbalanced three phase loads; and
Draft as of March 2012 50

Asymmetrical transmission impedances, caused by the mutual coupling between the
phases of a very long overhead transmission line.
4.11.2 Voltage Distortion Studies
Voltage distortions include harmonics, flicker (caused by e.g. non-linear loads such as arc
furnaces, rectifiers, and thyristor controlled devices), and voltage dips (caused by faults or
large load demand changes).
When new loads likely to generate harmonics are connected, specialists should be
approached to conduct harmonic studies to determine what level of harmonics can be
accepted and whether filters or other measures are required. For these types of studies, it is
typical to perform electromagnetic transient modeling.
Harmonic resonance problems may arise if shunt capacitors are installed. It is therefore
necessary for the Regulated Transmission Entity to perform harmonic resonance studies if a
new capacitor is to be installed to determine if harmonic filtering is required, or in extreme
cases to recommend another physical location or a different solution.
Flicker problems can be solved by increasing the fault level or by adding FACTS devices such
as SVC’s or by altering the behavior of the loads causing the problem.
Voltage dip problems should be investigated by applying three (3) phase faults to appropriate
points in the system and measuring the voltage dip at the substation near a sensitive load.
These studies provide information on the problem and it may be possible to reconfigure the
system to alleviate the situation.
4.12 RIGHT OF WAY AND ENVIRONMENTAL CONSIDERATIONS
The Regulated Transmission Entity is responsible to refer to the policies and guidelines
relating to environmental management that will affect the transmission system.
The Regulated Transmission Entity shall have due consideration for the implication of any
environmental impact study requirements from a planning perspective and also consider the
implication these studies may have on the schedule of proposed projects.
Furthermore, the Regulated Transmission Entity shall also have due consideration for the
potential implication from the process of right of way acquisitions and also understand the
implications this may have on the proposed projects and scheduling of projects.
Given that environmental impact studies and right of way matters are two of the variables that
may impact the scheduling of transmission system projects, the Regulated Transmission
Entity is required to consult with surveyors and environmentalists to assess the expected lead
time for any environmental impact study as well as the impact from negotiations with the
landowners. It is often expedient from an economic point of view to start these two processes
well in advance because they can be extremely time consuming. As a suggestion it is also
important, as far as is practicable, to simultaneously conduct the environmental impact study
and substation site acquisition process for all new transmission infrastructure needed over the
next 5 years or so within the same area so as to present landowners and other stakeholders
with a macro view of infrastructure requirements and minimize the risk of a public outcry
delaying the process.
Draft as of March 2012 51

5. TRANSMISSION ASSETS
5.1 INTRODUCTION
The following section provides some background information regarding different assets that
typically form part of a transmission system. The section serves to inform the Regulated
Transmission Entity of equipment standardization, current technology trends and other
general information regarding the different asset types.
5.2 TRANSFORMERS
Transformers are necessary to interconnect the different transmission voltages (500 kV, 230
kV and 138 kV) or to step-down from these voltages to supply large customers or DUs.
Normally, a specific transformer is selected taking into account the requirement for MVA
rating, number of units, type of units, winding connection and vector group, impedance,
insulation, type of tap changer and the range of taps for each unit. It is beneficial for the
Regulated Transmission Entity to set a standard range of transformers which will reduce
investments in spare units and to simplify replacements when required.
The standard transformer ratings can be selected to suit standard switchgear rupturing
capacities. The Regulated Transmission Entity shall always ensure that the fault contribution
through the transformers to the medium voltage (MV) busbar at new substations does not
exceed the standard switchgear rating at that voltage. However, it is noted that current
limiting reactors might be used to limit fault currents through transformers in specific
scenarios.
Since switchgear, protection, and civil works are relatively expensive, it could be more
economical to install a few large transformers rather than multiple small transformers. Smaller
transformers should however be installed if informed by the load forecast. In the event of fault
level constraints, it might be more economical to use smaller transformers rather than
replacing a large amount of underrated switchgear.
A transformer MVA rating should be selected to at least supply the load demand for a five (5)
year period in order to avoid the need for continuous and costly strengthening.
The tertiary ratings of transformers are normally high, but it is not recommended to use the
tertiaries to supply local systems or system reactors. Faults on the low voltage system are
more common and may result in loss of the transformer and long repair times which is not
favorable. The tertiaries can however be used to supply auxiliaries at the substation.
The transformer tap range must be selected to enable the transformer to convert a high
voltage (HV) of ninety five percent (95%) to an MV of one hundred and five percent (105%),
allowing for a five percent (5%) voltage drop in the transformer. This is to enable transmission
lines to run at a sending end voltage of one hundred and five percent (105%) and a receiving
end voltage of ninety five percent (95%) to obtain maximum power transfer at peak load. The
second tap range is to be selected to convert a one hundred and five percent (105%) HV to a
one hundred percent (100%) MV. This allows for a voltage rise of five percent (5%) on
transmission lines under light load conditions.
The load on any transmission transformer should not exceed its nameplate rating under
system healthy or contingency conditions when grid planning studies are conducted. The
Draft as of March 2012 52

overloading rating of any transformer should only be available for the system operator during
emergency conditions and not for planning purposes.
The table below provides a list of standard transformer sizes currently used by the Regulated
Transmission Entity.
Table 2: Standard Transformer Sizes used by the Regulated Transmission Entity
Transformers
Voltage Level (kV)
MVA Rating
500 600, 750
230 (Luzon) 50, 100, 300
230 (Visayas) 150
138 / 115 50, 75, 100
69 10, 20, 50
5.3 SWITCHGEAR
5.3.1 PCBs
The component used to connect or disconnect system components by disrupting the flow of
current is typically referred to as a circuit breaker. Circuit breakers typically act very quickly to
isolate faults on the system in order to safeguard the grid from any damage. In doing this,
circuit breakers are called to interrupt fault currents which can be much higher than normal
load currents.
The Regulated Transmission Entity needs to specify the applicable fault current rating
required for each substation and relevant switchgear. The appropriate rupturing capacity for
circuit breakers needs to be calculated by means of fault level studies. These studies need to
consider all new generation in the area for at least the next ten (10) years to ensure that the
rupturing capacity of the circuit breakers are not under estimated in the specification
documents. The Regulated Transmission Entity is advised to consult the switchgear
specialists regarding the latest standard circuit breaker ratings.
The table below provides a list of standard power circuit breakers currently used by the
Regulated Transmission Entity.
Table 3: Standard size for PCBs used by the Regulated Transmission Entity
Power Circuit Breaker
Voltage Level (kV)
Symmetrical Rating (kA)
500 40, 50
230 40, 50
Draft as of March 2012 53

Power Circuit Breaker
Voltage Level (kV)
Symmetrical Rating (kA)
138 40, 50
115 25, 31.5, 40
69 25, 31.5, 40
5.3.2 Isolators or Disconnecting Switches
Isolators (or Disconnecting Switches) are necessary to isolate the circuit breaker with a larger
physical distance, since the circuit breaker has only a small gap when it is in the open
position.
Isolators or disconnecting switches can be used for the following:
isolate electrical equipment from the system for maintenance or inspection; and
to connect feeders to different busbars.
The Regulated Transmission Entity needs to be aware that the isolators must have the
appropriate insulation level and be capable of carrying the full fault and load currents as
required for the associated circuit breaker. Furthermore, the Regulated Transmission Entity
must also consider the load current requirement of the isolators for at least a ten (10) year
planning horizon.
5.3.3 Gas Insulated Switchgear
Gas insulated switchgear (GIS) can be specified for certain applications as compared to
normal air insulated switchgear (AIS). A unit typically comprises a complete switch bay with
busbars, isolators, circuit breaker, earthing switches, CTs, voltage transformers (VTs) and
surge arresters. This compact equipment is typically enclosed in metal clad compartments and
insulated with SF 6 gas.
The advantageous of using GIS lies within the reduced space requirements, the reduced
environmental impact, reduced maintenance requirements and elimination of altitude and
pollution effects. GIS is very expensive compared to AIS solutions and for this reason the
Regulated Transmission Entity needs to justify clearly why a GIS solution is preferred over
AIS.
5.4 TRANSMISSION LINES
Appendix A list the standards used by the Regulated Transmission Entity for transmission line
design.
5.4.1 Design of Transmission Lines
Transmission lines provide transfer capability to remote areas in the transmission system and
additional capacity where lines already exist. The components of transmission lines include
support structures, insulators, conductors, earth wires and earth connections. Transmission
line design specialists use standard software programs to calculate the electrical parameters
Draft as of March 2012 54

of transmission lines based on their geometric configuration, conductor and the earth wire
types.
Transmission line structures could be self-supporting with galvanized steel lattice; guyed
suspension type (guyed vee); or cross rope suspension type. The selection of the structure is
mainly based on cost and environmental requirements.
Insulation can be provided by strings of glass insulator discs and long-rod or composite
insulators of various types where pollution or vandalism is a problem.
The conductors could be steel core aluminum (ACSR), copper (C), all aluminum (AAC),
aluminum alloy (AAAC) or even steel conductors.
Earth wires are installed to protect the line conductors by intercepting lightning strikes to the
line where required. These wires are usually constructed from galvanized steel and are solidly
connected to the structures. Optical fibers, for purposes of communication, may also be
included in the earth wires; however this communication solution increases earth wire costs
which would have to be justified.
Flash-overs 23 are typically caused by fires beneath lines, tree interference, salt pollution or
chemical pollution. From an operational perspective, where multiple lines are used, it is
desirable to have the lines installed along different routes to reduce the risk of simultaneous
loss of all lines. However, separate servitudes will require more negotiations with land owners
and more work relating to any environmental impact assessment requirements. In the event
that servitudes are difficult to obtain and the area is one of low lightning activity and not prone
to fires, consideration may be given to double circuit or multi circuit lines which are generally
more cost effective.
The Regulated Transmission Entity’s role is to investigate possible voltage levels and
conductor sizes which could meet the required power transfer over the required distance and
to recommend the most economic option which satisfies technical and environmental
requirements.
5.4.2 Thermal Limits
The power flow across any transmission line is limited by its thermal characteristics. There
are two thermal values of importance, the first is the continuous thermal rating and the second
is the emergency thermal rating. Normal planning studies should only consider operation to
the maximum continuous thermal rating and not consider the emergency thermal rating.
It is noted that the exact thermal limits of transmission lines are not an easy value to
determine due mainly to the difficulty in measuring the temperature on a transmission line.
This temperature is determined by multiple factors such as wind speed, wind direction,
intensity of solar radiation, air ambient temperature, terrain conditions, current flowing through
the conductor and more. Different methods are used to calculate the thermal capability of
conductors (also referred to as ampacity) including deterministic, probabilistic and real-time.
The most conservative approach in determining the thermal capability of conductors is the
deterministic method which assumes that all unfavorable conditions occur at the same time.
This method can be used as a first pass to check ratings of lines.
23 An unintended electric arc or electric discharge.
Draft as of March 2012 55

A less conservative but still acceptable method to use in determining the thermal capability is
the probabilistic method, which considers the stochastic nature of the meteorological
parameters. This method uses actual field data relevant to the area where the line is installed.
This method typically results in additional transfer capacity when these thermal limits are
imposed.
The use of real-time monitoring systems makes the statistical calculation method redundant.
This method will produce thermal limits which are generally higher than the previous two
methods, however there is a cost implication for this solution and it typically requires specialist
skills to implement.
Another option to increase power transfer on transmission lines is re-tensioning of existing
conductors, where applicable. This technique could typically be considered to impact the
implementation schedule of new infrastructure.
5.4.3 Voltage Limits
The power transfer across very long lines is typically limited by the voltage drop at the line
end, due to the load having a low power factor. The addition of shunt capacitors at the end of
the line will reduce the voltage drop and allow additional power transfer. A second or parallel
line should typically only be considered after the thermal limit of the first line is reached, unless
an N-1 criterion is considered and no other supplies are available to the particular load.
5.4.4 Conductor Optimization
Conductors account for roughly a third of the cost of an overhead transmission line and
account for the bulk of the transmission system losses. These are critical economic factors
which need careful analysis when selecting a conductor for a new overhead line, which will
typically be in operation for an excess of twenty-five (25) years. Choosing a larger conductor
configuration will have higher up front capital costs, but this may lead to lower overall life cycle
cost. If a conductor is not optimally selected, this would result in unnecessary system losses
and poor voltage regulation. It is therefore important that the Regulated Transmission Entity
prudently selects the optimal conductor type and tower configuration.
5.5 CAPACITORS (SERIES AND SHUNT)
5.5.1 General
Capacitors are used on the transmission system to maintain and regulate system voltages
within specified limits and also to increase the transfer capacity of a transmission line.
Series capacitors reduce the overall reactance (X) of a transmission line and therefore more
power can be transferred across the system. Shunt capacitors improve the receiving end
voltage (V 2 ) and hence also the transfer capability of the line.
Low voltages at the receiving end and/or voltage instability limits the power transfer capability
of long high voltage transmission lines. This voltage drop in a transmission line comprises two
components namely the product of the real power component of the current and the line
resistance, and the product of the reactive power component of the current and the line
reactance.
5.5.2 Shunt Capacitors
Shunt Capacitor Applications
Draft as of March 2012 56

Shunt capacitors are normally installed as close as possible to the relevant load centers for
maximum effectiveness in reducing line losses and controlling voltages. This type of shunt
capacitor bank installations is to improve the power factors at a substation. Therefore, shunt
capacitors should also preferably be located on the low voltage (LV) busbar of a substation to
reduce costs associated with switchgear and to improve the power factor.
Shunt capacitors are installed for one or more of the following purposes:
To maintain the voltage when variations in active or reactive power demand cause
variations in the voltage at the receiving end, shunt capacitors can be used in
combination with the tap changer of the transformer;
To improve the power factor when connected near the load which will also reduce the
requirement for reactive power from generators, reduce transmission loading and
losses in lines and transformers; and
To form part of harmonic filters installed to comply with the harmonic distortion levels
required.
When maintaining system voltages, the effectiveness of shunt capacitors to improve the
receiving end voltages and reduce power losses on a line is reduced for distribution voltage
levels (138 kV and below), because the active power component of the voltage reduction is
higher than for transmission voltage levels.
Bank Sizes
Shunt capacitor banks are made up of a number of capacitor units mounted on insulated
metal frames. The capacitor units are connected in series and parallel to provide the required
voltage and MVAr rating. Shunt capacitor banks could typically have the following ratings as
indicated below:
Table 4: Standard Ratings for Shunt Capacitor Banks
Shunt Capacitors
Voltage Level (kV)
MVAr Rating
230 50, 100
138 7.5, 20
115 7.5, 15
69 5, 7.5, 15
It is good practice to have shunt capacitor banks of standard MVAr ratings for each voltage
level.
Typically, shunt capacitors are less expensive than series capacitors and must be considered
first in order to overcome power transfer limitations due to voltage drop.
Draft as of March 2012 57

5.5.3 Series Capacitors
General
For longer lines where the permissible amount of shunt compensation is limited by voltage
stability, a combination of series and shunt capacitors can be proposed as planning solution.
Variable reactive power sources such as synchronous condensers or SVC’s could also be
used, but these components are typically more expensive.
Unlike shunt capacitors, series capacitors have an inherent effectiveness with increased load
especially during transient conditions which makes it an attractive solution to reduce voltage
dips due to sudden reactive changes in the power system.
Series Capacitor Application
Series compensation is not generally applied on 230 kV or lower voltage systems due to its
lower quality factor or X/R ratio 24 . As a general rule, if X/R is less than five, series capacitors
are not generally considered because the effectiveness and power transfer benefit is to low
and become uneconomically.
SSR is a concern when planning conventional 25 series capacitors due to the fact that they may
produce a tuned inductive-capacitive (LC) circuit which can, during certain conditions, excite
mechanical oscillations in generation facilities that are connected to the grid. These
mechanical oscillations can in turn excite the electrical system resulting in a resonant
condition at sub-synchronous frequencies (below 60 Hz) which may lead to damage to the
generator shafts. Solutions to prevent this SSR is available and includes FACTS devices
such as thyristor controlled series capacitors (TCSC) and at the power station SSR relay and
filters may be utilized.
Location and Configuration
Series capacitors can be located at any point along the transmission line but location at line
ends has advantages from maintenance and economical perspectives, since common
equipment and facilities can be shared when nearer to existing equipment. From a technical
perspective, the voltage profile also plays a role in selecting an adequate location for the
series capacitor and should therefore be studied to ensure an acceptable profile. The series
capacitor banks can also be located in the middle of the line (potentially providing better
voltage profiles) or split in two banks at the substations or a short distance from the
substation.
Modern protection allow for even as high as seventy-five percent (75%) compensation of a
line reactance which is a very high compensation level and could lead to over voltages at the
series capacitor bank. Typically, a maximum compensation value of sixty-five percent (65%) to
seventy percent (70%) shall not be exceeded.
Since series capacitors operate at line voltage, the capacitor cans and auxiliary equipment
(spark gap or metal oxide varistor (MOV), discharge reactors, bypass breakers, etc.) are
mounted on a platform which is insulated to withstand full line voltage.
24 Where X= Reactance and R=Resistance.
25 Conventional series capacitor banks are fixed impedance where the impedance of a thyristor controlled series capacitor
banks can be changed.
Draft as of March 2012 58

Rating and Design Philosophy
The design specification for a series capacitor needs to include thermal ratings for system
healthy or contingency conditions. The capacitors must be able to withstand the cyclical
overload ratings specified in the IEC standard. For transmission applications where
transmission lines are running in parallel, maximum line current through the series capacitor
occurs with one transmission line permanently out of service. Series capacitor ratings are
selected based on transmission line current limits (thermal ratings).
The actual current to which the bank is operated is important for which steady state
constraints are clearly defined in the IEC standard and identified in Section 4 of this guideline.
Another matter to consider for series capacitors is the transient over voltages caused by
mainly line related faults. Typically, over voltage protection is designed to limit the exposure of
the capacitor units from instantaneous voltages between capacitor terminals immediately
before or during operation of the over voltage protection.
Series capacitors are normally equipped with a by-pass breaker and a spark gap. If the
current flowing through the capacitor increases to unacceptable levels (typically when a fault
occurs), then the spark gap ignites, and if the arc does not disappear very quickly, the by-pass
breaker will close. New designs provide for a non-linear resistor, e.g metal oxide varistor (gapless
capacitor) which achieve the same purpose.
5.6 REACTORS (SERIES AND SHUNT)
Two types of designs are typically used for transmission reactors which include air core dry
type reactors or oil immersed reactors.
5.6.1 Application of Shunt Reactors
Reactors positioned in shunt to a busbar are used to control the voltage. The shunt reactance
compensates for the capacitance between the conductors of transmission lines or
underground cables. Reactors can be connected to the end of a line (normally via a breaker)
or to a busbar (always via a breaker). The purpose of a shunt reactor is:
To prevent excessive voltage rise during light load conditions;
To reduce the reactive power swing when switching a transmission line;
To reduce the need for the generating source to absorb excessive reactive power;
and
To reduce switching over voltages.
To prevent excessive voltage rise, the most effective position for shunt reactors is at the
receiving end 26 of a transmission line. Shunt reactors compensation may be required at both
ends of a line when the line is very long and the charging current is in excess of the capability
of the sending end generation; or in a case where excessive over-voltage exists on the
sending end busbars.
26 Receiving end is defined as the load side or weak source side of the transmission line.
Draft as of March 2012 59

It is advised that the Regulated Transmission Entity and system operator should be in
agreement from which end the line will be re-energized after a fault and a lockout. This reenergizing
should take place in such a way to minimize the risk of over voltage, but also to
minimize the number of shunt reactors required.
Shunt reactors are normally connected to the transmission line via a circuit breaker in order for
the line to be functional if the reactor is faulty or requires maintenance. The reactor bay can
typically be designed in such a way that the line reactor can become a busbar reactor when
the line is out of service.
The Regulated Transmission Entity should, as far possible, refrain from connecting reactors to
transmission transformer tertiaries because of possible damage to the transformers.
The table below provides a list of standard reactors used in the transmission system at
present.
Table 5: Standard Size of Reactors Used
Shunt Reactors
Voltage Level (kV)
MVAr Rating
500 30, 90
230 25, 35, 50, 70
138 7.5, 15, 20, 40
115 7.5, 15
69 7.5, 15
5.6.2 Switchgear
Reactor switching requires a circuit breaker having suitable characteristics. Line reactors
should not be directly connected to the line without an isolating switch. All reactors must be
connected through circuit breakers.
5.6.3 Other Types of Reactors
Neutral earthing reactors limit the line to ground fault (single phase fault) current to specified
limits and are typically applied to generator transformers and transmission line connected
reactors.
Current limiting reactors are air cooled reactors and do not have any magnetic circuit (in order
not to reduce their reactance value beyond saturation point). These reactors are used to
reduce the short circuit current to levels within the rating of the equipment and are applied at
any voltage level. Duplex reactors are a special type of current limiting reactor which consists
of two half coils, wound in opposition in order to provide a low reactance under normal
conditions and a high reactance during fault conditions.
Capacitor reactors are designed to be installed in series with a shunt connected capacitor
bank and are used to limit in-rush or transient currents due to switching or closing circuit
Draft as of March 2012 60

eakers when a fault exists in the transmission system; and also to control the resonant
frequency of the system due to the addition of a capacitor bank.
Smoothing reactors are used to reduce the magnitude of the ripple current in an HVDC
system.
Load flow control reactors are series connected reactors on transmission lines of any voltage
level which changes the line impedance characteristic such that load flow can be controlled,
hence, ensuring maximum power transfer over adjacent transmission lines.
Filter reactors are used in conjunction with capacitors to provide a tuned series or parallel
resonant LC-circuit for specific harmonic currents which is typically found in equipment such
as SVCs.
5.7 HVDC SCHEMES
Transmission systems comprising long and multiple alternating current (AC) transmission lines
typically require shunt reactive power control at regular intervals to control the voltage profile.
However, on DC transmission lines, only real power is transmitted and hence no need for
reactive power compensation along the line. The converter stations, however, require a large
amount of reactive power (about fifty-five percent (55%) of the active power), including filters
to eliminate harmonics generated by the converting equipment.
HVDC transmission is designed for large amounts of power to be transmitted over long
distances typically from remote generation facilities to load centers. The only limiting factor in
the practical length of an HVDC transmission system is the DC line voltage drop which results
from the line resistance and current. As a rough benchmark, break-even distance when
comparing HVDC versus AC solutions from an economic perspective is between six hundred
(600) to eight hundred (800) kilometers (km) for overhead lines and fifty (50) km for cables
(undersea or underground). To transmit the same amount of power, HVDC lines are cheaper
than AC lines, but the terminal equipment is more expensive and more complex than AC
substations.
Conventional line commutated converters require a minimum fault level of approximately two
and a half (2.5) times the power transfer for reliable commutation.
Furthermore, HVDC is suitable for load flow control and thus transmission system
stabilization. HVDC transmission could also facilitate network coupling between networks with
different frequencies or different control philosophies.
A major benefit of HVDC transmission compared to AC is its ability to isolate an AC system
from the worst effects of a transient fault in the adjoining AC system and the inherent
robustness of the interconnection in the presence of difficult AC system conditions.
Different HVDC Schemes and Converter Types
HVDC light or MV DC systems use low power (one hundred (100) MW to five hundred (500)
MW), and is forced commutated converter-based systems with insulated gate bipolar
transistor (IGBT) semiconductor devices. These systems are ideal to interconnect weak
networks with strong networks or to connect sources of renewable energy (for example wind
power) with the rest of the system.
Voltage sourced converters (VSCs) do not require a minimum fault level at the receiving end
and are able to provide almost independent control of active and reactive power. VSCs are
Draft as of March 2012 61

more expensive and have higher losses than traditional line commuted converters and are
used for DC transmission projects of ratings of typically up to two hundred (200) to three
hundred (300) MW.
Capacitor commutated converters (CCC) have a series capacitor on the DC side of the
converter transformer and have the advantage of requiring a further reduced minimum fault
level for reliable commutation. Further advantages are that the series capacitor provides most
of the reactive power consumed by the converter, thus reducing the rating and cost of the
converter transformer as well as reducing shunt compensation requirements.
5.8 FACTS DEVICES
Equipment such as transformers, generators, shunt capacitors, shunt reactors and series
capacitors can typically manually be inserted or taken out of service by a system operator to
control voltage and power in a transmission system. There exist multiple devices that
automate the operation of equipment, providing fast and better control of the grid. This is
generally achieved by devices containing thyristor based electronics and micro-processors
and are referred to as FACTS devices. These FACTS devices may offer the following benefits
to the network:
Increase power transfer limits and operating limits;
Improve network dynamic stability;
Fast voltage control (transient interaction);
Slower reactive power control;
Compensation on long transmission lines;
Improved quality of supply;
Contribute to power oscillation damping;
Reduce SSR impact; and
Reduce network harmonic resonance.
5.8.1 SVCs
SVCs is probably the most used and known FACTS device (apart from HVDC). SVCs are
typically more expensive than static devices that can perform the same steady state function
as an SVC and are employed where a dynamic range of compensation is required with a fast
response time. SVCs are generally used for the following reasons:
Fast inductive control of over voltages after loss of large loads;
Fast capacitive control of under voltages due to loss of generation of transmission
lines;
Slow reactive power control to pre-determined values;
Improvement in quality of supply, i.e. flicker, unbalance between phases for traction
loads;
Draft as of March 2012 62

Damping of SSR;
Prevent resonance by displacing the natural frequency of the transmission system or
any harmonic frequency; and
Assist with power oscillation damping.
SVC installations typically comprise a transformer, filter elements, thyristor controlled reactor
(TCR) and its control system. Thyristor switched capacitors (TSCs) could also form part of an
SVC or can be placed outside the SVC which can be controlled externally from the SVC.
Therefore, the SVC control system might control remote shunt capacitors and reactors in the
same substation if so desired.
To determine the size of an SVC, dynamic studies are required in which the dynamic range
(capacitive and inductive) needs to be determined. The SVC must never be allowed to
saturate to either end of its dynamic range. As load demand increases, the SVCs capacitive
capability might be used in steady state scenarios but in such cases the Regulated
Transmission Entity needs to ensure that the SVC will remain able to function as originally
intended. Power transfer studies should typically exclude any SVC models if they are not
specifically installed to provide steady state support.
Lastly, it is possible to construct SVCs in modules or containers that are re-locatable which
could assist in providing short term solutions to system stability if required.
5.8.2 STATCOM
STATCOM is also sometimes referred to as an advanced SVC. Contrary to a normal SVC, the
STATCOM use gate turnoff (GTO) thyristors. Furthermore, the SVC uses actual shunt
capacitors and reactors whereas the STATCOM uses only a small capacitor that serves as
storage element. The STATCOM exchange reactive power amongst the three phases of an
AC transmission circuit by absorbing energy for part of a cycle 27 and then returning it at
another part of the cycle. Another characteristic of a STATCOM is that reactive power output
is more independent of voltage when compared with an SVC which means performance
remains the same even during lower system voltages. STATCOM devices are expensive and
are used more often for distribution systems.
5.8.3 TCSC
TCSC devices are the dynamic counterpart of a series capacitor and therefore control the
effective impedance of the transmission line to which it is connected. Typical functions of a
TCSC are listed below:
Power flow control – The TCSC impact on power flow will be seen on parallel
transmission lines and is useful from an operational perspective to force power across
different corridors when required due to varying loads and during maintenance
periods;
Power swing damping – Changing the degree of compensation of the transmission
line can contribute in damping of power swings by increases power transfer over lines
that are stability limited; and
27 Cycle refer to alternating current for which the movement of electric charge periodically reverses direction.
Draft as of March 2012 63

SSR damping – Active modulation could be used in the TCSC to dampen SSR
frequencies.
Lastly, TCSC solutions are relatively expensive but costs could be reduced by combining the
TCSC control with a normal series capacitor.
5.8.4 Unified Power Flow Controller (UPFC)
The UPFC is a combination of a TCSC and a STATCOM but is generally very expensive.
5.8.5 Thyristor Controlled Breaking Resistor (TCBR)
A TCBR is used to damp real power flows very quickly and are more effective than its
mechanical counterparts, which needs to be switched manually and is therefore not as
effective. TCBRs are typically installed near generation facilities to prevent massive in-rush
currents in certain parts of the transmission system or excessive generation acceleration
following a large load rejection. TCBRs are usually very expensive devices.
5.9 BUSBAR
Apart from transmission lines, transformers and other plant, the reliability and availability of the
transmission system is also dependent on busbar arrangements. It is noted that busbar faults
often lead to the loss of several lines or transformers and although such faults are (or should
be) rare, they are responsible for a significant portion of typical system minutes losses.
Draft as of March 2012 64

6. TRANSMISSION PLANNING IN A MARKET ENVIRONMENT
6.1 INTRODUCTION
The implementation of the EPIRA including the commercial operations of the WESM heralded
a new era of decentralized decision making for the power industry. The market reforms
necessitate changes to grid planning. This section will discuss the necessary steps to be
undertaken by the Regulated Transmission Entity in order to ensure an effective and efficient
grid planning process in this market environment.
6.2 COORDINATION AMONG THE REGULATED TRANSMMISSION ENTITY, GRID
CUSTOMERS, SYSTEM OPERATOR AND MARKET OPERATOR
In a market environment, transmission planning will have direct impacts on both system
operations and market operations in the WESM which is based on the security constrained
economic dispatch, specifically on the dispatch of generating units and pricing of energy and
reserves, and consequently the financial performance of the market participants/customers.
Effective coordination between the Regulated Transmission Entity, the grid customers, the
system operator and the market operator at the grid planning process will contribute to more
efficient and effective grid planning. This includes:
incorporating the relevant WESM features in the grid planning methodology; and
the grid customers, the system operator and the market operator playing a
contributory role in the grid planning process while the Regulated Transmission Entity
maintains its lead responsibility for transmission planning. Effective coordination helps
ensure that the Regulated Transmission Entity’s congestion alleviation projects take
account of the grid customers’ projects for mitigating the impacts of transmission
congestions such as demand side management and new generation capacities.
6.3 OPEN ACCESS AND GRID PLANNING
As stated in the EPIRA, “open access” refers to the system of allowing any qualified person
the use of transmission, and/or distribution system, and associated facilities subject to the
payment of transmission and/or distribution retail wheeling rates duly approved by the ERC.
Open access does not mean a grid that is transmission congestion-free. In the WESM, a
generation facility has to compete with other generation facilities for the transmission
resources beyond its connecting substation. A congestion-free grid planning would result in
overcapacity in the transmission system and increase the transmission cost, leading to market
inefficiency.
6.4 ALLEVIATION OF CONGESTION TO ENHANCE MARKET EFFICIENCY
The Regulated Transmission Entity will have the lead responsibility for identifying the
congestion problems that may result in increased outages or raise the cost of service or the
electricity prices due to transmission congestions significantly. 28 When transmission
congestion occurs at a line, a more expensive generating unit has to be dispatched out of the
merit order in order to meet the load demand. It sends signals for more efficient generation
28 While the PGC does not clearly define this responsibility, it is assumed that future amendments of the PGC will include this
responsibility of the Regulated Transmission Entity.
Draft as of March 2012 65

and load management in the short run and for investment opportunities in generation, demand
side management and transmission in the long run.
A CAPEX proposal which is targeted at the alleviation of congestion to enhance market
efficiency and effectiveness shall be assessed, ranked and prioritized on the same financial
analysis basis as other CAPEX proposals. This will require the estimation of the congestion
cost of a transmission line through Market Impact Studies.
6.5 MARKET IMPACT STUDIES TO ASSESS IMPACT ON WESM OF CONGESTION
ALLEVIATION CAPEX PROJECTS
The Market Impact Studies shall be conducted to assess the impact on the WESM
participants or customers of the congestion alleviation CAPEX projects. The studies shall
estimate the congestion costs arising from transmission congestions and the potential
economic benefit to the WESM participants or customers of these congestion alleviation
projects.
6.6 IMPACT OF DIFFERENT GENERATION PATTERNS
The congestion alleviation projects shall be put alongside with other CAPEX projects for
ranking and prioritizing in transmission planning as described in Section 7. Any congestion
alleviation project may materially alter the optimal generation mix in a power market and the
dispatch quantity for generation facilities may increase or decrease as a result. This is a
commercial risk that all market participants or customers have to manage in a market
environment and a market participant or customer shall not dispute a congestion alleviation
project which meets the planning criteria and complies with the planning process outlined in
this guideline on the grounds of being adversely affected by this project (i.e., the estimated
higher or lower electricity prices or the estimated reductions in the dispatch quantity).
Therefore, it is essential that the estimation of the congestion cost through the Market Impact
Studies follows the methodology and process outlined in Section 7.2.4 of this document.
Draft as of March 2012 66

7. PROJECT SELECTION AND DOCUMENTATION
7.1 INTRODUCTION
This section provides guidance in relation to the process of evaluation, prioritization and
documentation of projects. The guidance provided is at a high level only and it remains the
responsibility of the Regulated Transmission Entity to further enhance the processes outlined
in this section.
Transmission system development is usually established on an N-1 criterion, which is used as
the basis for determining the technical requirements of the grid. When the system
development is based purely on the N-1 criterion, this is referred to as deterministic planning.
In striving to develop a transmission system which is fully compliant on the N-1 criterion, there
are important aspects to consider which includes the current state of the system, deliverability,
budgetary and physical constraints.
The current level of N-1 criterion compliance of a system will provide an indication of the
magnitude of CAPEX requirement to improve the transmission system in order to be fully
compliant. In some cases, the required CAPEX may be so high that attaining full compliance
may not be possible in the short term due to deliverability or budgetary constraints. In such a
scenario it is important for the Regulated Transmission Entity to also use probabilistic
planning 29 methods to improve CAPEX efficiency and to develop a medium to longer term
strategy to improve system reliability. 30
Budgetary and deliverability constraints exist for any utility which restricts CAPEX for purposes
of system development. For this reason, it is important for the Regulated Transmission Entity
to prioritize projects by identifying the more important projects to be implemented over the
planning period. Physical constraints also exist in the transmission system which the
Regulated Transmission Entity needs to be aware of in preparing any development plan.
The Regulated Transmission Entity needs to follow a specific process to formulate and
properly document any project. With a proper documentation process in place, the Regulated
Transmission Entity will be in a better position to defend different technical solutions and
expenditure proposals to industry participants. Thus, the Regulated Transmission Entity
should endeavor to prepare adequate documentation that will address the numerous
questions that will arise from the review of any submission to the ERC. This guideline serves
to assist the Regulated Transmission Entity in preparing documentation specifically for
purposes of one such review procedure, which forms part of the regulatory reset process.
7.2 PROJECT EVALUATION
It is of utmost importance for the Regulated Transmission Entity that in proposing projects, the
driver(s) or the reason(s) why a project is necessary is also identified. Classifying projects in
29 Probabilistic planning has the potential to result in a delay of a project to some extent relative to the probability of a
combination of events. This can include the probability of line outages and maintenance, generation availability and outage
scheduling, the size of the load, the load factor, the cost of the long run marginal generation and the cost to the customer.
These probabilities are all considered to determine a more appropriate year of installation of the proposed project. Care
should be taken to not assume that probabilistic planning will be the norm used for planning, since it may lead to inadequate
grid planning and increased difficulty in operating the transmission system.
30 Please note that the WESM has already established a methodology which incorporates some of the “probabilistic” items and
may potentially be used as an input in the CAPEX decision process, this methodology is embodied in the Market Dispatch
Optimization Model (MDOM).
Draft as of March 2012 67

terms of the different drivers will also assist the Regulated Transmission Entity in
understanding how a proposed project relates to other projects forming part of the overall
development plan. Below is a list of typical drivers for projects:
Connection of new generation facility;
Load growth in a specific area, areas, or substation;
Connecting a new load;
The refurbishment of aging plant;
Compliance to statutory requirements, for example safety requirements;
Compliance to the PGC;
Improving of the system reliability and security (Establishing of a backbone – strategic
planning), including N-1 contingency compliance;
Introduction of a new voltage level (strategic decision);
Congestion alleviation; and
Planning of interconnections between utilities, islands, grids or areas.
In most cases, technical solutions affect the transmission system in more than one way, for
example, addressing a steady state requirement may lead to the solution impacting transfer
capability, stability, fault level contributions and losses. Thus, the Regulated Transmission
Entity is responsible to assess different technical solutions and weigh all the technical benefits
for each solution against each other. Even so, there will be a main driver for each proposed
project which will be used to classify each project for purposes of further assessment.
The succeeding subsections detail the process to be followed by the Regulated Transmission
Entity in evaluating projects.
7.2.1 Defining the Problem
After identification of the main and other supporting drivers, the Regulated Transmission Entity
should now define the problem associated with the particular project which could be one of the
following:
Overloading of transmission lines;
Overloading of power transformers or substations;
Voltage collapse in specific areas
o
Reached transfer limits in an area or at a substation;
Non-compliance to the PGC or planning criteria;
Aging of equipment, system reliability;
High fault levels, system reliability;
Draft as of March 2012 68

Low voltages, quality of supply;
Bad power factor, quality of supply and impact on voltage profile;
Congestion; and
Stability problems
o
o
o
Transient stability
Small signal stability
SSR.
7.2.2 Selecting Potential Solutions
The problems identified can be resolved by applying different technical alternative solutions.
Some of the alternatives will be more suitable than the other from a technical point of view and
others from an economic viability point of view. It is the task of the Regulated Transmission
Entity to identify the best solution that will satisfy the given criteria and is also a technoeconomic
solution.
The technically suitable alternatives will depend on the system requirements. Some of the
technologies available to the Regulated Transmission Entity are discussed in Section 5.
For the economic or financial component of the evaluation, the Regulated Transmission Entity
is required to perform a Net Present Value (NPV) for each alternative as well as other
appropriate analysis as required in Section 7.2.5.
The Regulated Transmission Entity must evaluate all the possible solutions for a specific
project in such a way that a proper techno-economic proposal that also takes into account
operating in a market environment is presented to the ERC and to industry participants. Also,
clear standards need to be established to evaluate the different alternatives. These standards
will be different from project to project and will be guided by the type of project, size of project,
requirements of the customer and funds available for the project. In order to ensure the
selection of adequate alternative solutions, all alternative solutions must always solve the
problem and comply with all requirements including that set by the PGC.
Below is a non-exhaustive list of items that could be used as an initial guide to evaluate a
project and alternative solutions:
Potential CAPEX for the project;
Impact on system losses;
Improvement in power transfer capability;
Impact on fault levels;
Impact of Expected Energy Not Supplied (EENS);
Impact of outage probabilities;
Impact on congestion;
Draft as of March 2012 69

Identify if it is a short term solution (once off) or long term (phasing of many projects);
and
Identify the time-line required to implement each alternative.
7.2.3 Technical Analysis
To assist in identifying the final technical project solution, the Regulated Transmission Entity
should undertake specialized system studies taking into account all the requirements, impact
on the transmission system and the financial or economic viability of the project. The following
studies will be required:
Load flow analysis
o
o
System intact
Contingency analysis;
Power transfer limits (Voltage collapse);
Calculate fault levels;
Conduct appropriate stability studies;
Calculate system losses for all the scenarios;
Calculate EENS; and
Perform a detailed costing of the final alternatives. This will be used for the economic
or financial justification of the project as set out in the least economic cost analysis
discussion in Section 7.2.5. The costing of a project needs to be done and presented
to a level of detail adequate for review purposes by the industry participants. It may
further assist the review process if a standard list of equipment prices are used and
documented as part of the numerous proposed projects to improve transparency in
unit price selection.
7.2.4 Market Analysis
Market Simulation Model
The Regulated Transmission Entity shall use the Market Simulation Model, which is based on
the Market Dispatch Optimization Model (MDOM) set out in Section 3.6 “MDOM” of the WESM
Rules and Section 4.2 “Basis Algorithm of the MDOM” specified in the Price Determination
Methodology (PDM), in co-optimizing energy and regulating contingency reserves under the
N-1 requirements.
As stated in the PDM, the MDOM aims to maximize the economic gain derived from electricity
trades in the market, considering the constraints imposed by the existing system conditions.
The objective of the Market Simulation Model, which shall be the same as that in the MDOM,
which is to maximize:
Value of dispatched load based on demand bids,
Minus the cost of dispatched generation based on generation offers,
Draft as of March 2012 70

Minus the cost of dispatched reserve based on reserve offers,
Minus the cost of constraint violation based on constraint violation coefficients.
The Regulated Transmission Entity shall be responsible for ensuring that this model is audited
by an independent auditor before it is used for grid planning for the first time and subsequently
whenever it is modified to incorporate the changes to the PDM to ensure that it complies with
Section 3.6 “MDOM” of the WESM Rules and Section 4.2 “Basis Algorithm of the MDOM” of
the PDM.
The Regulated Transmission Entity shall develop in-house modeling capability in carrying out
market simulations for grid planning purposes. However, it may outsource the simulation work
to an independent entity.
Constraint Violation Coefficients (CVC)
The system of CVC used in the MDOM or PDM is a mechanism for signaling the security risks
in the system through the scheduling and dispatch process. It prioritizes the system security
constraints which will be violated in the presence of system security risks.
The Market Simulation Model shall use the same constraint violation coefficients as that
specified in the WESM Manual CVC as shown in the table below:
Table 6: CVC Costs
Constraint Violation Coefficient Name
Deficit Interruptible Load Reserve (Insufficient
Interruptible demand to meet Reserve
Requirement)
Deficit Dispatchable Reserve (Insufficient capacity
to meet Reserve Requirements)
Over Generation (the total minimum generation in
the system exceeds the total demand)
Deficit Regulating Reserve (Insufficient capacity to
meet Reserve Requirements)
Deficit Contingency Reserve (Insufficient capacity
to meet Reserve Requirements)
Contingency (Violation in pre-defined contingency
limits during single-outage conditions)
Under Generation (demand > total maximum
generation in the system)
Base Case Constraint (Thermal loading limit
violations of lines or transformers)
TCG Constraint (Import or Export constraints
between areas)
Nodal Value of Lost Load (Localized deficiency in
supply due to line or transformer loading limitations)
Price (PhP/MW)
100,000
200,000
(800,000)
400,000
500,000
600,000
800,000
900,000
1,000,000
1,100,000
Draft as of March 2012 71

The simulated congestion cost associated with a transmission line is an indicator for the
potential benefit to the buyers of electricity when the transmission congestion caused by this
line is alleviated. This information may then be incorporated into the cost-benefit analysis of
the CAPEX proposal, discussed under the “Least Economic Cost Analysis” of Section 7.2.5
below, which aims at alleviating this congestion in the grid planning process.
Grid Configuration Data for Market Simulation Model
The grid configuration for the Market Simulation Model shall be developed based on the
Market Network Model published by the market operator for scheduling, dispatch and pricing.
While the Market Network Model specifies the detailed grid for real-time operations, the grid
configuration for the Market Simulation Model for grid planning may be a reduced version of
the Market Network Model as long as the modeling of the system security constraints is not
compromised (e.g., the transmission lines that may become congested and cause material
congestion costs during the planning horizon must be modeled). A reduced grid configuration
will help ensure the efficiency of the market simulation process.
The Regulated Transmission Entity shall specify its assumption on the interconnections
among the grids and specifically if the dispatch simulations are performed on a grid by grid
basis or jointly as a market (e.g., if the Luzon grid and the Visayas grid are modeled together
as a single market).
Market Economic Data for Market Simulation Model
The merit order of all generating units for the Market Simulation Model shall be formed in
principle based on the estimated short run marginal cost (SRMC) of each generating unit.
The Regulated Transmission Entity is responsible for the estimation of the SRMC of each
generating unit, taking account of the technology and age of the generating unit and the
associated fuel cost. While the actual SRMC figures are not required and the historic offer
data by the generation facilities may not reflect the SRMC for the planning horizon, the
Regulated Transmission Entity shall be transparent in the estimation of the SRMC by
documenting the methodology for the estimation of the SRMC for forming the merit order for
grid planning.
The Regulated Transmission Entity shall use the most recent load demand data, including the
hourly load for each modeled node, and project forward using the load forecast prepared in
accordance with Section 2 of this guideline.
In preparation for the simulations for grid planning, the Regulated Transmission Entity shall
calibrate the Market Simulation Model to ensure that the load weighted average price (LWAP)
for the most recent year calculated by this model is in line with the underlying average
generation cost for that year (e.g., the average generation charge of the unbundled electric
bills).
Simulation of Dispatch and Scheduling based on the WESM Rules
The Market Simulation Model, which is based on the MDOM or PDM and specifies a Market-
Network-Model-consistent grid configuration, shall generate simulation results which are
consistent with the market dispatch and pricing outcomes if the same inputs (offer price and
quantity) are used.
The main simulation outputs that shall be used for grid planning include
Draft as of March 2012 72

• The objective function value in pesos
• Identification of the transmission lines which are congested
The simulation horizon for grid planning shall be the same as the planning horizon.
For each year of the simulation horizon, it is not required to simulate the market outcomes for
each trading interval. Instead, the simulations may be conducted for representative trading
intervals (load segments), which shall cover different load levels (e.g., representative load
segments based on the hourly WESM load data) and supply seasonality (e.g., dry and wet
seasons).
To assist the planning process, the Regulated Transmission Entity may use scenario analysis
to assess the sensitivity of emerging grid security risks during the planning horizon with
respect to different assumptions.
Baseline Case for Grid Planning
In preparation for market simulations for grid planning, the Regulated Transmission Entity
shall firstly establish a pre-baseline case for the planning horizon, which incorporates only the
forecast load growth. This pre-baseline case will be used to highlight potential transmission
congestions and signal investment opportunities in generation capacity, demand side
management and transmission capacity, similar to the “Statement of Opportunities” in some
countries.
The Regulated Transmission Entity shall then establish the baseline case, which incorporates
not only the forecast load growth, but also forecast generation capacity additions and forecast
demand side investment; but without the CAPEX proposals which alleviates transmission
congestions.
Congestion Cost
The congestion cost in a trading interval in the WESM is the difference between the
Unconstrained Economic Benefit and the Constrained Economic Benefit as calculated by the
MDOM or the Market Simulation Model for that trading interval. It shall not be adjusted for the
segregated or unsegregated line rental which consists of the loss rental and the congestion
rental.
In conducting the simulations to calculate the congestion cost, the Regulated Transmission
Entity shall specify whether (1) any must-run unit is scheduled and (2) the price substitution
methodology (PSM) is applied in the simulation process.
Note that congestion may occur without violation of any constraints. In these cases, the
contribution to the Objective Function value of the cost of constraint violation is zero.
The congestion cost for a year is the sum of the trading interval (load segment) based
congestion cost calculated for that year.
For grid planning,
the Constrained Economic Benefit is the Objective Function value associated with the
baseline case established in this Section 7.2.4 under “Baseline Case for Grid
Planning”.
Draft as of March 2012 73

the Unconstrained Economic Benefit is the Objective Function value associated with
the case which is based on the grid configuration which includes the CAPEX proposal
which alleviates transmission congestion.
Estimation of Congestion Cost Including under N-1 Conditions
For grid planning, the likely congestion cost shall be estimated by using the Market Simulation
Model regardless whether the grid is part of the WESM, as the long term planning is based on
the security constrained economic dispatch principle as the WESM, which includes the N-1
requirement and co-optimization of energy and reserve to ensure efficient resource
allocations.
The likely congestion cost shall be calculated for both the total peso value and the pesos per-
MWh/kWh basis for each transmission line with congestion for each trading interval or load
segment modeled and then grossed up for the planning horizon. The pesos per megawatt
hour (MWh) or kWh congestion cost is calculated as the ratio of the total peso value of
congestion cost to the total load in MWh or kWh for the corresponding period.
Investments Intended to Alleviate Congestion
The total peso value of the congestion cost for each congested line provides an indication of
the potential benefit to the customers of the CAPEX project which alleviates this congestion.
This information shall be incorporated into the cost-benefit analysis (detailed under the “Least
Economic Cost Analysis” of Section 7.2.5), of the congestion alleviation project which aims to
alleviate the congestion at this line.
7.2.5 Financial Analysis
This section endeavors to highlight the financial impact of each project and also provides
insight into the appropriate scheduling or prioritization of each project. For this analysis there
are three types of investment categories namely operating cost reduction, least economic
cost, and statutory or strategic investments.
A particular project may have more than one investment category applied to it and for such
cases the financial assessment should be applied in the following order:
a) Operational cost reduction analysis;
b) Least economic cost analysis; and
c) Statutory or strategic analysis.
Moreover, in the event that only the operational cost reduction investment criterion applies to a
particular project, the Regulated Transmission Entity is not required to conduct the least
economic cost and statutory or strategic analyses. In the event that only the least economic
cost investment criterion applies, only the operational cost and least economic cost analysis
will be undertaken. However, in both these cases and even though it is not a requirement,
project justification could be improved by including any additional factors as motivation.
Operational Cost Reduction Analysis
All projects for which the focus is to reduce operating costs falls under the investment
category of operational cost reduction. A typical example of such projects will be those where
equipment is specifically replaced to reduce maintenance costs.
Draft as of March 2012 74

To test project viability, it is necessary to apply lifecycle cost analysis to each project by using
the discounted cash flow (DCF) analysis that compares the NPV of the project and reductions
in operating costs over its expected lifetime against the NPV of costs expected to be incurred
if the project is not implemented.
NPV = ( PV of future cash inflow ) - ( PV of future cash outflow )
where
and
PV n = Cash Flow n / (1 + (r / 100)) n
PV n = Present Value of Cash Flow n
n = number of years
r = real discount rate in %
= {[(1 + (i /100)) / (1 + (e / 100))] -1} x 100%
i = nominal interest rate in %
e = escalation or inflation rate in %
If the project has a lower lifecycle cost than a scenario without implementing the project
(positive NPV scenario), it would indicate that it is viable in terms of the operational cost
reduction criterion alone.
To ensure consistency, the lifecycle cost of all alternatives must be evaluated over the same
period. Only planned maintenance and other costs easily calculable in advance shall be
included as operating costs and it is noted that these costs shall exclude expected savings in
breakdown repair costs. A reduction in breakdown frequency and/or duration will result in
improved reliability of supply for which the benefits should be quantified using the least
economic cost method in cases where the project cannot be justified by the operational cost
reduction method alone.
In cases where assets are assessed for excessive operational costs, allowance should be
given for the replacement of the current asset at the end of its remaining life.
If the project has a higher lifecycle cost than a scenario without implementing the project, it
would indicate that the project is not viable in terms of the operational cost reduction criterion
and therefore the least economic cost method should now be applied.
Even though a positive NPV scenario may indicate that a project is viable, this does not
always indicate the optimal timing for the actual investment and for this reason the method
below should be applied. The method calculates the equal annual capital charge of the
project by determining a capital recovery factor over a pay-back period equal to the standard
asset life of the asset at the real discount rate.
Equal Annual Capital Charge = Capital Recovery Factor x Project Capital Expenditure
Capital Recovery Factor
= r / [1 - (1 + r)-n]
where
r = Real Discount Rate (%)
n = Number of years (standard asset life)
Draft as of March 2012 75

The project is not only viable but also justified from a timing perspective when the equal
annual capital charge is smaller than the expected annual cost reduction (the saving in
operational costs due to the new project less the extra operational costs caused by the new
project).
For all projects, a sensitivity analyses shall be performed on applicable parameters which
would typically include discount rate, equipment failure rates, currency fluctuations, estimated
cost reductions and more.
It is important to note that it is not necessary for the net savings in operational cost to be
favorable over the expected life of the project in order for the investment to qualify for inclusion
in the Regulated Transmission Entity’s rate base. This is so because there are projects that
may not necessarily be financially viable to the Regulated Transmission Entity but may be
beneficial looking at the power industry as a whole. In such cases, the Regulated
Transmission Entity will have to clearly present the benefits to the industry on the same bases
as used for other projects.
Least Economic Cost Analysis
Least economic cost analysis aims at identifying the least-cost project alternative for providing
the desired outcome. Least economic cost analysis involves comparing the costs of the
various mutually exclusive, technically feasible project alternatives and selecting the one with
the lowest cost. 31 One of these project alternatives will always be the “do nothing” option
which will ensure that the overall viability of the alternative projects are also assessed.
Some examples where the least economic cost method will typically be applied include:
Investments for improved supply reliability and/or quality;
Transmission projects including extensions, strategic spares, special maintenance
and refurbishment expenditure;
Investments aimed at alleviating congestion;
To determine and/or verify the desired level of network or equipment redundancy; and
To evaluate investments intended to provide new or increased supplies to customers
and generation facilities.
It is recognized that improving reliability or quality of supply easily impacts more industry
participants than just the Regulated Transmission Entity and it is therefore important to take
note of the overall impact of the proposed project in terms of the overall CAPEX for the project
versus the overall benefit to the customer.
It is further recognized that it is to a certain extent easier to quantify the CAPEX for the
proposed project than defining the benefits derived by the customers from such a project. To
define the benefits to the customer, the reduction in EENS due to the improvement in the
quality of supply must be calculated and the value of this energy derived (typically from the
extra energy sales). The indirect cost of unserved energy is best known by the customers
themselves and a function of numerous factors including the time of interruption, type of load,
31 Mutually exclusive alternative projects must produce the same output of a specified service quality. If differences in output or
service quality exist, a normalization process must be followed to ensure equivalence.
Draft as of March 2012 76

duration and frequency of the interruption, availability of customer back-up generation, indirect
damage caused, customer subsequent start-up costs, the availability of customers own
generation and more. From the above, it is prudent to obtain information regarding indirect
costs from customer surveys.
Another method in defining benefits to the customer is by using the total peso value of the
congestion cost for each congested line, for instances when the CAPEX project is aimed at
alleviating congestion. This method is discussed in more detail in Section 7.2.4 above.
Below is an equation where the value of the improved quality of supply is compared with the
CAPEX proposed for the project: 32
Value (PhP/kWh) x Reduction in EENS to Customers (kWh) > CAPEX to Reduce
EENS (PhP)
From the above equation, it is apparent that if the value of the improved quality of supply to
the customer (Value (PhP/kWh) x Reduction in EENS to Customers (kWh)) is less than the
cost to the Regulated Transmission Enitity, then this project is not viable from a least cost
perspective.
Note that the reduction in EENS relates to all improvements to the quality of supply including
fewer power interruptions, parameters being outside limits (for example voltage dips, levels
and unbalances) affecting the customer. The reduction in EENS is calculated by establishing
the probability that the power system is constrained through one or more components being
out of service.
For all projects, a sensitivity analyses should be performed on applicable parameters which
would typically include discount rate, equipment failure rates, currency fluctuations, estimated
cost reductions and more.
Statutory or Strategic Analysis
Statutory investments are investments that the Regulated Transmission Entity is legally
required to make, irrespective of whether they are justifiable in financial terms and includes
investments in response to ERC directives, legislation, court orders, compulsory contractual
commitments, and others.
Strategic investments are of a discretionary nature intended to achieve objectives not
measurable in financial terms and could include the acquisition of strategic power corridor
servitudes or substation sites.
For both statutory and strategic projects, an attempt should be made to justify these projects
on financial bases prior to categorizing it as statutory or strategic from the onset. Even though
it may be proved that these projects is not financially viable, the financial analysis should still
be documented for completeness and to indicate the financial impact of the CAPEX project.
Project justifications should include adequate legal or strategic arguments in order to be
considered.
32 Value of the improved quality of supply is the value of the additional energy that would have been supplied to the customers if
the power interruption did not occur and could be calculated on probabilistic bases.
Draft as of March 2012 77

7.3 PRIORITIZATION
Based on the output from the technical, market and financial analysis, the Regulated
Transmission Entity shall assess the ranking of the different viable projects taking into account
the constraints in terms of budget, deliverability, and the physical constraints of the system.
Moreover, the Regulated Transmission Entity shall as well take into account the strategic
objectives of the company and other factors the Regulated Transmission Entity believes would
affect the undertaking of a project over the regulatory period. Such ranking will provide an
indication of the priority of the projects and should therefore be fully documented as defined in
the succeeding section.
7.4 PROJECT DOCUMENTATION
Documenting all relevant information for each project is a challenging process and needs to
be done keeping in mind that the documentation should be adequate so that industry
participants need not require significantly more information than what has already been
provided by the Regulated Transmission Entity to be able to perform their necessary
assessment of each project. The documentation for each project shall consist of all necessary
details (some of the necessary details are discussed under the technical, market and financial
analyses in Section 7.2) and show all the findings to date as well as an executive summary for
each. All the key information on the project needs to be addressed with costs as well as the
project implementation program.
For some of the projects (which includes all projects categorized as a least economic cost
project), the Regulated Transmission Entity will be required to conduct a sensitivity analysis
and this should form part of the technical description in the documentation. As indicated in
Section 7.2, the sensitivity analyses should be performed on applicable parameters which
would typically include discount rate, equipment failure rates, currency fluctuations, estimated
cost reductions and more. A sensitivity analysis could be required for any of the following
project drivers:
Load growth scenarios;
Generation patterns;
Voltage levels;
Transmission line conductors;
Transformer sizes;
Location of generation facility;
Routes of transmission lines; and
Financial impact as described in Section 7.2.5.
The project documentation needs to be structured well and consistently with all other projects.
The steps below could be used as a guide to structure the project document:
Identify the need for the investment;
Define the problem;
Draft as of March 2012 78

List all the assumptions used in the study;
Description of the network simulation model used and the years of study in terms of
load, generation and network;
Identify and describe all the alternatives;
Study all the alternatives;
Document the findings
o
o
List the Pros and Cons of each alternative
Document the technical, market and financial assessments;
Full discussion on all technical issues related to solve the problem;
Financial analysis of each alternative studied including categorization;
Perform a sensitivity analysis where required; and
Build a business case or project justification for the project.
Section 4.10 of the RTWR and Section 3.2 of the Position Paper 33 state that projects
amounting to PhP 50 million or more will be classified as major projects. It is also important to
note that the RTWR is stating clearly that related CAPEX should be grouped together into a
single project and should not be sub-divided. The following provide an overview of the
minimum documentation requirement for the different project classifications.
Project less than PhP 50 million, minor projects
Short description of the project;
Describe the type of project;
Drivers identified for the project;
Project cost per annum;
Implementation plan per annum, with a list of equipment required annually;
Impact on system operations;
Impact on future projects;
Impact on EENS; and
Impact on system technical losses.
Project more than PhP 50 million, major projects
Detailed report of alternatives studied;
33 Position Paper for the Regulatory Reset for the NGCP for 2011 to 2015, Energy Regulatory Commission, Philippines,
September 2009.
Draft as of March 2012 79

Describe the type of project;
Drivers identified for the project;
Project cost per annum
o
Project and equipment cost breakdown;
Implementation plan per annum, with a list of equipment required annually;
Impact on system operations;
Impact on future projects;
Impact on EENS;
Impact on system technical losses;
Single line diagrams with and without the project; and
List of equipment and ratings, e.g. MVA, kV, A, MVAr, length, etc.
For all projects
Financial categorization and analysis; and
List of project rankings with detailed explanation of ranking assessment.
Draft as of March 2012 80

REFERENCES
Annual Transmission Planning and Evaluation Report (FERC FORM No. 715), New York Independent
System Operator, April 2009.
Applied Mathematics for Power Systems, E. A. Feinberg and D. Genethliou, State University of New
York, New York.
Business Intelligence in Economic Forecasting: Technologies and Techniques, F. Elakrmi and N. A.
Shikhah, Amman University, Jordan.
CIGRE Special Report for Group 14 (FACTS and HVDC), 2002.
Computer Analysis Methods for Power Systems, G.T. Heyat, New York.
Demand Forecasting for Electricity, N. Bohr.
Electric Power Industry Reform Act (Republic Act No. 9136), Congress of the Philippines, July 2000.
Electric Power Systems Research Journal volume 37, “New Index Parameter for Rapid Evaluation of
Turbo-generator Sub-synchronous Resonance Susceptibility”, G D Jennings and R G Harley, Elsevier,
Switzerland, 1996.
Eskom Planning, Design and Construction of Overhead Power Lines volume 1, Crown Publications,
Johannesburg, 2004.
Fuzzy Ideology based Long Term Forecasting, J. H. Pujar, World Academy of Science, Engineering
and Technology, India.
International Journal of Systems Science volume 33, “Electric Load Forecasting: Literature Survey and
Classification of Methods”, H. Alfares and M. Nazeeruddin, United Kingdom, 2002.
Long Term Energy Consumption Forecasting Using Genetic Programming, K. Karabulut, A. Alkan, A.
Yilmaz, Yasar University, Turkey, 2008.
Philippine Distribution Code, Energy Regulatory Commission, Philippines, December 2001.
Philippine Grid Code Amendment No. 1, Drafted by Grid Management Committee, Reviewed and
Approved by Energy Regulatory Commission, Philippines, April 2007.
Position Paper for the Regulatory Reset for the NGCP for 2011 to 2015, Energy Regulatory
Commission, Philippines, September 2009.
Power System Planning, Howard Technology, Middle East.
Power System Stability and Control, Prabha Kundur, McGraw-Hill Education.
Power System Voltage Stability, Carson Taylor, McGraw-Hill Education, 1994.
Revised Rules, Terms and Conditions for the Provision of Open Access Transmission Service, Energy
Regulatory Commission, Philippines, January 2009.
Rules and Regulations to Implement Republic Act No. 9136, Entitled “Electric Power Industry Reform
Act of 2001”, Department of Energy, Philippines, February 2002.
Rules for Setting Transmission Wheeling Rates for 2003 to around 2027, Energy Regulatory
Commission, Philippines, September 2009.
Draft as of March 2012 81

The Price Determination Methodology for the Philippine Wholesale Electricity Spot Market (Revision
23), Approved by the Energy Regulatory Commission, Philippines, January 2006.
The South African Grid Code: The Network Code Version 7, National Energy Regulator, South Africa,
March 2008.
Transmission Planning Guide, National Grid Corporation of the Philippines, Philippines.
Transmission Planning Guideline for Northeast Utilities, Northeast Utilities System, May 2008.
Transmission Planning Guidelines (Revision 1), Orange & Rockland Transmission and Substation
Engineering Department, May 2008.
Transmission Planning Utility Guidelines, Letter and Paper from Manila Electric Company addressed
to the ERC, Philippines, May 2011.
WESM Manual, “Load Forecasting Methodology Issue 0.0”, Philippine Wholesale Electricity Spot
Market, Philippines, August 2004.
WESM Manual, “Methodology for Determining Pricing Errors and Price Substitution Due to Congestion
for Energy Transactions in the WESM Issue 3.0”, Philippine Wholesale Electricity Spot Market,
Philippines, November 2010.
Wholesale Electricity Spot Market (WESM) Rules, Department of Energy, Philippines, June 2002.
Draft as of March 2012 82

APPENDIX A: LIST OF STANDARDS USED BY THE REGULATED
TRANSMISSION ENTITY FOR TRANSMISSION LINE DESIGN
Draft as of March 2012 83

Standard Transmission Line Impedance Characteristics *
Typical Positive & Negative Sequence Data per km (in pu at 100 MVA base)
(For New Transmission Lines Only)
Voltage Level
(kV)
Resistance R
(pu/km)
Reactance X
(pu/km)
Susceptance B
(pu/km)
500 ST DC 4 795 MCM 0.000008 0.000135 0.012437 2772
500 SP DC 4 795 MCM 0.000010 0.000130 0.012430 2772
500 ST SC 4 795 MCM 0.000008 0.000135 0.012437 2772
230 ST DC 4 795 MCM 0.000042 0.000554 0.002987 1276
230 SP DC 4 795 MCM 0.000040 0.000500 0.003265 1276
230 ST DC 2 795 MCM 0.000083 0.000622 0.002644 638
230 ST DC 1 795 MCM 0.000166 0.000885 0.001864 319
230 SP SC 4 795 MCM 0.000042 0.000554 0.002987 1276
230 SP SC 2 795 MCM 0.000080 0.000655 0.002510 638
230 SP SC 1 795 MCM 0.000166 0.000955 0.001745 319
230 ST SC 1 795 MCM 0.000166 0.000955 0.001745 319
230 SP SC 2 610 mm 2 TACSR 0.000025 0.000505 0.004205 1364
230 SP SC 2 410 mm 2 TACSR 0.000070 0.000630 0.002610 1082
230 ST SC 2 410 mm 2 TACSR 0.000070 0.000640 0.002570 1082
230 SUB-CABLE 630 mm 2 0.000134 0.000169 0.061822 260
138 ST DC 1 795 MCM 0.000450 0.002500 0.000660 191
138 ST SC 1 795 MCM 0.000380 0.002460 0.000200 191
138 UGC DC 1400 mm 2 0.000299 0.000640 0.019319 200
138 SUB-CABLE 300 mm 2 0.001740 0.001067 0.025229 108
115 SP SC 2 795 MCM 0.000309 0.002345 0.000686 318
115 ST SC 2 795 MCM 0.000309 0.002349 0.000696 318
115 SP SC 1 795 MCM 0.000662 0.003356 0.000493 159
115 ST SC 1 795 MCM 0.000660 0.003360 0.000490 159
115 ST DC 1 795 MCM 0.000660 0.003320 0.000500 159
69 ST DC 1 795 MCM 0.001790 0.010320 0.000160 96
69 ST SC 1 795 MCM 0.001798 0.008558 0.000192 96
69 SP SC 1 795 MCM 0.001800 0.008809 0.000080 96
69 ST SC 1 336.4 MCM 0.004056 0.009079 0.000183 56
* subject to future updates
Structure Type
No. of
Circuits
No. of Bundled
Conductors
Size of Conductor
Notes:
1. 795 MCM ACSR - Condor ST - Steel Tower SC - single circuit
2. 336.4 MCM ACSR - Linnet SP - Steel Pole DC - double circuit
3. Conductor Temperature (ACSR) - 90 °C UGC - Underground Cable
4. Conductor Temperature (TACSR) - 150 °C
5. For overhead lines - Ambient Temperature: 40°C; wind velocity: 0.5 m/sec
Positive & Negative Sequence Data
MVA Rating
(per circuit)
Draft as of March 2012 84

STANDARDS FOR TRANSMISSION LINE DESIGN
Material/Description
Standard Number and Title
1. Lattice Steel Tower AISC - American Institute of Steel Construction
- Specification for Structural Steel Buildings (June 1, 1989)
- Code of Standard Practice for Steel Buildings and Bridges (September 1,
1992)
ASTM -American Society for Testing and Materials
A36-92 Standard Specification for Structural Steel
A123-89 Standard Specification for Zinc (Hot-Galvanized) Coatings on
Products Fabricated from Rolled, Pressed, and Forge Steel,
Plates, Bars and Strips
A143-89 Recommended Practice for Safeguarding Against Embrittlement
of Hot-Dip Galvanized Structural Steel Product and Procedure
for Detecting Embrittlement
A153-82 Standard Specification for Zinc Coating
A239-89 Standard Test Method for Locating the Thinnest Spot in a Zinc
(galvanized) Coating of Iron or Steel Articles by the Preece Test
(Copper Sulfate Dip)
A325-93 Standard Specification for High-Strength Bolts for Structural
Steel Joints, Including Suitable Nuts and Plain Washers
A384-80 Recommended Practice for Safeguarding against Warpage and
Distortion during Hot-dip Galvanizing of Steel Assemblies
A394-93 Standard Specification for Galvanized Steel Transmission Tower
Bolts and Nuts
A563-93 Standard Specification for Carbon and Alloy Steel Nuts
A572/A573M Specification for High-Strength Low Alloy Columbium-
Vanadium Steels of Structural Quality
F436-82 Standard Specification for Hardened Steel Washers
AWS - American Welding Society
D1.1-92
A5.1-91
A5.17-89
Structural Welding Code - Steel
Specification for Carbon Steel Covered Arc-Welding Electrodes
Specification for Carbon Steel Electrodes and Fluxes for
Submerged Arc-Welding
AZI -
American Zinc Institute
Inspection Manual for Hot-Dip Galvanized Products (Latest Edition)
ASCE - American Society of Civil Engineers
Design of Latticed Steel Transmission Structures, (ANSI/ASCE October
1990, ANSI Approved December 9, 1991)
2. Transmission Steel
Pole
ASTM -American Society for Testing and Materials
A36/A36M Standard Specification for Structural Steel, Book 01.04
A123 Specification for Zinc (Hot-Dip Galvanized) Coatings on Iron
and Steel Products, Book 01.06, 15.08.
A143-89 Recommended Practice for Safeguarding Against
Embrittlement of Hot Dip Galvanized Structural Steel Product
A153
and Procedure for Detecting Embrittlement
Specification for Zinc Coating (Hot Dip) on Iron and Steel
Hardware, Book 01.06.15.08.
A239-89 Standard Test Method for Locating the Thinnest Spot in a Zinc
(Galvanized) Coating of Iron or Steel Articles by the Preece
Draft as of March 2012 85

Test (Copper Sulfate Dip)
A307 Standard Specification for Carbon Steel Bolts and Studs,
60,000 psi Tensile, Book 01.01, 15.08
A325 Specification for Structural Bolts, Steel, Heat Treated, 120/105
ksi Minimum Tensile Strength, Book 15.08
A354 Specification for Quenched and Tempered Alloy Steel Bolts,
Studs and Other Externally Threaded Fasteners
A370 Test Methods and Definitions for Mechanical Testing of Steel
Products
A384 Recommended Practice for Safeguarding against Warpage and
Distortion during Hot-dip Galvanizing of Steel Assemblies
A394 Standard Specification for Galvanized Steel Transmission
Tower Bolts and Nuts
A435 Standard Specification for Straight Beam Ultrasonic
Examination of Steel Plates for Pressure Vessels
A449 Specification for Quench and Tempered Steel Bolts and Studs
A490 Specification for Heat Treated, Steel Structural Bolts, 150 ksi
(1035 Mpa) Tensile Strength
A563 Specification for Carbon and Alloy Steel Nuts
A572/A573M Specification for High-Strength Low Alloy Columbium-
Vanadium Steels of Structural Quality
A588/A588M Specification for High Strength Low-Alloy Structural Steel with
50 ksi (345 Mpa) Minimum Yield Point to 4 in. (100mm) Thick
A615 Standard Specification for Deformed and Plain Billet Steel Bars
for Concrete Reinforcement
A633/A633M Specification for Normalized High Strength Low Alloy Structural
Steel
A673/A673M Specification for Sampling Procedure for Impact Testing of
Structural Steel
A687 Specification for High Strength Non-Headed Steel Bolts and
Studs
A780 Practice for Repair of Damaged and Uncoated Areas of Hot-Dip
Galvanized Coatings
A871/A871M Specification for High Strength Low Alloy Structural Steel Plate
With Atmospheric Corrosion Resistance
F436-82 Standard Specification for Hardened Steel Washers
AWS - American Welding Society
D1.1-92
A5.1-91
A5.17-89
Structural Welding Code - Steel
Specification for Carbon Steel Covered Arc-Welding Electrodes
Specification for Carbon Steel Electrodes and Fluxes for
Submerged Arc-Welding
AZI - American Zinc Institute
Inspection Manual for Hot - Dip Galvanized Products (Latest Edition)
ASCE - American Society of Civil Engineers
ASCE Manual No.72, “Design of Steel Transmission Pole Structures,”
Second Edition, 1990
3. Power Conductors ANSI/IEEE - American National Standards Institute and/or Institute of
Electrical & Electronic Engineers
IEEE Std. 524
IEEE Guide to the Installation of Overhead Transmission
Line Conductors-2003
ASTM -American Society for Testing Materials
B193
Test Method for Resistivity of Electrical Conductor Materials
Draft as of March 2012 86

B230 Aluminum Wire, 1350-H19 for Electrical Purposes
B231 Aluminum Conductors, Concentric-Lay-Stranded
B232 Aluminum Conductors, Concentric-Lay-Stranded Steel
Reinforced (ACSR)
B263 Test Method for Determination of Cross-Sectional Area of
Stranded Conductors
B341 Aluminum-Coated (Aluminized) Steel Core Wire for Aluminum
Conductors, Steel Reinforced
B398 Aluminum Alloy 6201-T81 Wire for Electrical Purposes
B399 Concentric-Lay-Stranded Aluminum-Alloy 6201-T81
Conductors
B498 Zinc-Coated (Galvanized) Steel Core Wire for Aluminum
Conductors, Steel Reinforced (ACSR)
B500 Zinc-Coated (Galvanized) and Aluminum-Coated (Aluminized)
Stranded Steel Core Wire for Aluminum Conductors, Steel
Reinforced (ACSR/AZ)
B502 Aluminum-Clad Steel Core Wire For Aluminum Conductors,
Aluminum-Clad Steel-Reinforced (ACSR/AW)
B524 Concentric-Lay-Stranded Aluminum Conductors, Aluminum-
Alloy Reinforced (ACAR, 1350/6201)
B549 Concentric Lay Stranded Aluminum Conductors, Aluminum
Clad Steel Reinforced (ACSR/AW)
B802/802M Standard Specification for Zinc-5% Aluminum-Mischmetal
Alloy-Coated Steel Core Wire for Aluminum Conductors, Steel
Reinforced (ACSR)
B803
B856
Standard Specification for High-Strength Zinc-5% Aluminum-
Mischmetal Alloy-Coated Steel Core Wire for Aluminum and
Aluminum Alloy Conductors Steel Reinforced
Standard Specification for Concentric Lay Stranded Aluminum
Conductors, Coated Steel Supported (ACSS)
E-139 Conducting Creep, Creep-Rupture, and Stress-Rupture Tests
of Metallic Materials
IEC -International Electrotechnical Commission Publications
60104 Aluminum-Magnesium-Silicon Alloy Wire for Overhead Line
Conductors
60888 Zinc-Coated Steel Wires for Stranded Conductors
60889 Hard-Drawn Aluminum Wire for Overhead Lines
61089 Round Wire Concentric Lay Overhead Electrical Stranded
Conductors
61232 Aluminum Clad Steel Wires for Electrical Purposes
61395 Creep Test Procedures for Overhead Conductors
62004 Thermal-Resistant Aluminum Alloy Wire for Overhead Line
Conductors
62420 Concentric Lay Stranded Electrical Conductors containing one
or more Gaps
4. Overhead Ground Wire ANSI/IEEE – American National Standards Institute and/or Institute of
Electrical & Electronic Engineers
IEEE Std. 524
IEEE Guide to the Installation of Overhead Transmission
Line Conductors - 2003
ASTM - American Society for Testing Materials
A363 Standard Specification for Zinc-Coated (galvanized) Steel
Overhead Ground Wire Strand
A474 Standard Specification for Aluminum-coated Steel Wire Strand
A925-03 Standard Specification for Zinc-5% Aluminum- Mischmetal
Alloy- Coated Steel Overhead Ground Wire
Draft as of March 2012 87

B341
B193
B415
B416
B502
Standard Specification for Aluminum-Coated (Aluminized) Steel
Core Wire for Aluminum Conductors, Steel Reinforced
Test Method for Resistivity of Electrical Conductor Materials
Standard Specification for Hard-Drawn Aluminum-clad Steel
Wire
Standard Specification for Concentric-Lay-Stranded Aluminum-
Clad Steel Conductors
Standard Specification for Aluminum Clad Steel Core Wire for
Aluminum Conductors, Aluminum-Clad Steel Reinforced
(ACSR/AW)
E-139 Conducting Creep, Creep-Rupture, and Stress-Rupture Tests
of Metallic Materials
IEC -
International Electrotechnical Commission Publications
60888 Zinc-Coated Steel Wires for Stranded
Conductors
61089 Round Wire Concentric Lay Overhead
electrical Stranded Conductors
61232 Aluminum Clad Steel Wires for
Electrical Purposes
5. Line Insulators ANSI/IEEE - AMERICAN NATIONAL STANDARDS INSTITUTE
C29.1-88 Test Methods for Electrical Power Insulators
C29.2 Wet Process Porcelain and Toughened Glass Insulators -
Suspension Type
C29.9 Wet Process Porcelain Insulators- Apparatus, Post Type
C29.11-89 Tests for Composite Suspension Insulators for Overhead
Transmission Line
IEEE 4-78 Standard Techniques for High Voltage Testing
IEEE 957 Guide for Cleaning Insulators
IEEE 987 Guide for Application of Composite Insulators
ASTM - American Society for Testing and Materials
A153 Specification for Zinc Coating (Hot-Dip) on Iron and Steel
Hardware
A239-89 Standard Test Method for Locating the Thinnest Spot in a Zinc
(galvanized) Coating of Iron or Steel Articles by the Preece Test
(Copper Sulfate Dip)
B499 Method for Measurement of Coating Thickness by Magnetic
Method; Non- Magnetic Coatings on Magnetic Basis Metals
D750 Recommended Practice for Operating Light and Weather
Apparatus (Carbon Arc Type) for Artificial Weather Testing of
Rubber Compounds
D1499 Recommended Practice for Operating Light and Water
Exposure Apparatus (Carbon Type) for Exposure of Plastics
D2240 Rubber Properties - Durmeter Hardness
D25 Recommended Practice for Operating Xenon-Arc Light Water
G23
Exposure Apparatus for Plastics
Recommended Practice for Operating Light and Water
Exposure Apparatus ( Carbon Type) for Exposure of Nonmetallic
Materials
G26 Recommended Practice for Operating Light Exposure
Apparatus (Xenon Arc Type) with or without Water for Exposure
of Non-metallic Materials.
G53
Recommended Practice for Operating Light Exposure and
Water Exposure Apparatus ( Fluorescent UV-Condensation
Type) for Exposure of Non-metallic Materials
IEC -International Electrotechnical Commission
60060-1 General Definitions & Test Procedures
Draft as of March 2012 88

60120 Dimensions of Ball and Socket Couplings of String Insulator
Units
60305 Characteristics of String Insulator Units of the Cap and Pin
Type
60372 Locking Devices for Ball and Socket Couplings of String
Insulators
60383 Tests on Insulators of Ceramic Material or Glass for Overhead
Lines with a Nominal Voltage greater than 1000 V
60433 Characteristics of String Insulators Units of the Long Rod Type
60437 Radio Interference Test on High Voltage Insulators
60438 Tests and Dimensions for High Voltage D.C. Insulators
60471 Dimensions of Clevis and Tongue Coupling of String Insulator
Units
60506 Switching Impulse Tests on High Voltage Insulators
60507 Artificial Pollution Tests on High Voltage Insulators to be used
on A.C. Systems
60575 Thermal-mechanical Performance Test and Mechanical
Performance Test on String Insulator Units
60591 Sampling Rules and Acceptance Criteria when Applying
Statistical Control Methods for Mechanical or Glass for
Overhead Lines with a Nominal Voltage Greater than 1000 V
60815 Guide for Selection of Insulators in Respect of Polluted
Conditions
1109-92 Composite Insulators for AC Overhead Lines with Nominal
Voltage Greater than 1000V - Definitions, test methods and
acceptance criteria.
CEA - Canadian Electrical Association
LWIWG-01 and -02
Design and Type Test Methods for Composite
Insulators
6. Line Hardwares ASTM -American Society For Testing And Materials
A 90 Weight of Coating on Zinc-Coated (Galvanized) Iron and Steel
Articles
A 123 Zinc (Hot-Galvanized) Coatings on Products Fabricated from
Rolled, Pressed and Forged Steel Shapes, Plates, Bars and
Strip.
A 143 Safeguarding Against Embrittlement of Hot Galvanized
Structural Steel products and Procedure for Detecting
Embrittlement
A 153
A 239
Zinc-Coating (Hot-Dip) on Iron and Steel Hardware
Test for Locating the Thinnest Spot in a Zinc (Galvanized)
Coating on Iron or Steel Articles by the Preece Test (Copper
Sulfate Dip)
A 394 Galvanized Steel Transmission Tower Bolts and Nuts
A 370 Mechanical Testing of Steel Articles
A 435 Straight-Beam Ultrasonic Examination of Steel Plates
A 440 High Strength Structural Steel
A 441 High-strength Low-Alloy Structural Manganese Vanadium Steel
A 572 High-Strength Low-Alloy Columbium-Vanadium Steels of
Structural Quality
E 8 Methods of Tension Testing of Metallic Materials
7. Optical Fiber Ground
Wire (OPGW)
ANSI/IEEE - American National Standard Institute/Institute of Electrical and
Electronic Engineers
53-1981 Packaging Standards for Aluminum Conductor and ACSR
359-A-1981 Standard Colors for Identification and Coding
1138-1994 Standard Construction of Composite Fiber Optic Overhead
Ground Wire (OPGW) for Use on Electric Utility Power Lines
Draft as of March 2012 89

ASTM - American Society for Testing Materials
A363 Zinc-Coated (galvanized) steel Overhead Ground Wire Strand
A474 Aluminum-Coated Steel Wire Strand
B398-1990 Specification for Aluminum Alloy 6201-T81 Wire for Electrical
Purposes
B415 Specification for Hard-Drawn Aluminum-Clad Steel Wire
B416 Concentric-Lay-Stranded Aluminum-Clad Steel Conductors
E139 Conducting Creep, Creep-Rupture, and Stress-Rupture Tests
of Metallic Materials
E 29-1990 Practice for Using Significant Digits in Test Data to Determine
Conformance with Specifications
EIA - Electronic Industries Association
455-3A-1989 Procedures to Measure Temperature Cycling Effects on Optical
Fibers, Optical Cables, and other Passive Fiber Optic
Components
455-25A-1989 Repeated Impact Testing of Fiber Optic Cables and
Cable Assemblies
455-30B-1991 Frequency Domain Measurement of Multimode Optical
Fiber Information Transmission Capacity
455-31B-1990 Fiber Tensile Proof Test Method
455-41-1985 Compressive Loading Resistance of Fiber Optic Cables
455-45B-1992 Microscopic Method for Measuring Fiber Geometry of
Optical Waveguide Fibers
455-48B-1990 Measurement of Optical Fiber Cladding Diameter Using
Laser-Based Instruments
455-50A-1987 Light-Launch Conditions for Long Length, Graded Index
Optical Fiber Spectral Attenuation Measurements
455-51A-1991 Pulse Distortion Measurement of Multimode Glass
Optical Fiber Information Capacity
455-55B-1990 End-View Methods for Measuring Coating and Buffer
Geometry of Optical Fiber
455-58A-1990 Core Diameter Measurement of Graded Index Optical
Fibers
455-62A-1992 Measurement of Optical FiberMacrobend Attenuation
455-78A-1990 Special Attenuation Cutback Measurement for Single
Mode Optical Fibers
455-82B-1992 Fluid Penetration Test for Fluid-Blocked Fiber Optic
Cable
455-164A-1991 Single Mode Fiber, Measurement of Mode Field Diameter
455-167A-1992
by Far-Field Scanning
Mode Field Diameter Measurement, Variable Aperture
Method in the Far-Field
455-168A-1992 Chromatic Dispersion Measurement of Multimode
Graded Index and Single-Mode Optical Fibers by
Spectral Group Delay Measurement in the Time Domain
455-169A-1992
Chromatic Dispersion Measurement of Single-Mode
Optical Fibers by Phase Shift-Method
455-170-1989 Cable Cutoff Wavelength of Single-Mode Fiber by
Transmitted Power
455-173-1990 Coating Geometry Measurement for Optical Fiber, Side
View Method
455-174-1988 Mode Field Diameter of Single-Mode Optical Fiber by
Knife-Edge Scanning in the Far Field
455-175A-1992
Chromatic Dispersion Measurement of Single-Mode
Optical Fibers by the Differential Phase-Shift Method
455-176-1993 Method for Measuring Optical Fiber Cross-Sectional
Geometry by Automated Grey-Scale Analysis
455-177A-1992 Numerical Aperture Measurement of Graded-Index
Draft as of March 2012 90

Optical Fibers
IEC - International Electrotechnical Commission Publications
60104 Aluminum-Magnesium-Silicon Alloy Wire for Overhead Line
Conductors
60304 Standard Colors for Identification and Coding
60793-1 Optical Fibers Part 1: Generic Specification
60794-1-E1 Tensile Performance of Optical Fiber Cables
60794-1-E3 Crush Strength Test of Fiber Optic Cable
60794-1-E6 Bending Test for Optical Fiber Cable
60794-1-F1 Temperature Cycling Tests on Optical Fibers
60794-1-F5 Longitudinal Water Tightness
61089 Round Wire Concentric Lay Overhead electrical Stranded
Conductors
61232 Aluminum Clad Steel Wires for Electrical Purposes
ITU –T - International Telecommunication Union
G.650 Definition and Test Methods for the Relevant Parameters of
Single-Mode Fibers
G.652 Characteristics of a Single Mode Optical Fiber Cable
G.655 Characteristics of a Non-Zero Dispersion Shifted Optical Fiber
8. Quality Manual ISO -International Standards Organization
9. Local Standard PEC - Philippine Electrical Code
9001 Quality System Model for Quality Assurance in
Design/Development, Manufacture and Testing
9002 Quality System Model for Quality Assurance in Production,
Installation and Servicing
Part 2, Latest Edition
Draft as of March 2012 91