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Home » Decision #069-09-EAC on Approval and Issue of Grid Code_090522

Decision #069-09-EAC on Approval and Issue of Grid Code_090522

Published: 2011 Sep 19

KINGDOM OF CAMBODIA
NATION  RELIGION  KING

ELECTRICITY AUTHORITY OF CAMBODIA
No. 069-09-EAC

Phnom Penh, May 22, 2009

DECISION
ON APPROVAL AND ISSUE OF GRID CODE

ELECTRICITY AUTHORITY OF CAMBODIA

-Having seen the Electricity Law of the  Kingdom of Cambodia promulgated by the Royal
KRAM No. NS/RKM/0201/03 dated February 2, 2001

-Having seen the Royal Decree No. NS/RKT/0408/378 of April 4, 2008 of Preahbath Samdech
Preah NORODOM SIHAMONY, the King of the Kingdom of Cambodia, on the appointment
of Excellency TY NORIN as  Chairman of Electricity Authority of Cambodia for a renewed
term

-In accordance with the consultation with concerned Ministries, institutions, and licensees made
from November 4, 2008 to March 31, 2009

In accordance with the decision of EAC’s session No. 156 dated May 22, 2009

DECIDES

Article 1:
To approve and issue the regulation called Grid Code under the Electricity Law of the
Kingdom of Cambodia to establish the basic rules, requirements, procedures and standards that
govern the operation, maintenance and development of the High Voltage Transmission System
in Cambodia.
Article 2:
The regulation has the content as in the attached document.

Article 3:
The regulation is applicable to National Transmission Licensee, Special Purpose
Transmission Licensees operating High Voltage transmission system and the Users of the High
Voltage Transmission System.

Article 4:
The regulation shall come into force from the date of signing.

Article 5:
The Secretariat of Electricity Authority of Cambodia shall publicize the regulation.

CHAIRMAN
ELECTRICITY AUTHORITY OF CAMBODIA

CC:
-Ministry of Industry, Mines and Energy
-EDC
-Special Purpose Transmission Licensee operating HV transmission system
-Users of High Voltage Transmission System
-Archives

CAMBODIA
GRID CODE

MAY 2009
KINGDOM OF CAMBODIA
NATION RELIGION KING

Cambodia Grid Code

Preface

The Cambodia Transmission System (CTS) is in very early stage of development. Till
November 2007, the Phnom Penh System was the only transmission systems in
Cambodia. The Phnom Penh System consists of a number of 115 kV lines connecting
a number of sub-stations and generating plants to supply electricity to Phnom Penh
and the areas around it. Some of the generating plants are connected to the system at
medium voltage through the subtransmission/distribution system. Electricité Du
Cambodge (EDC) owns the HV, MV and LV lines and substations and some of the
generating plants; while the other generating plants are owned by Independent Power
Producers (IPPs), who sell the electricity generated by them to EDC.

In November 2007 the North-West Transmission System (connecting Thailand system
with Banteay Meanchey, Siem Reap and Battambang through 115 kV transmission
lines) was commissioned. A Special Purpose Transmission Licensee owns and
operates this 115 kV system and has a transmission agreement with EDC. Electricity
is purchased by EDC from Thailand and  supplied to its customers in Banteay
Meanchey, Siem Reap and Battambang. Subtransmission system is being constructed
to take power supply to other towns and rural areas of these three provinces.

Projects are ongoing to get electric power to Cambodia through high voltage lines
from Vietnam and Laos. In future there may be more External Interconnections to the
CTS for import of power from other systems or export of power to other systems. In
the coming years more generating plants  and transmission lines are planned. Such
additions will extend the existing systems, create new separate systems and
interconnect the separate system to form larger systems. With gradual reinforcements
and extensions, the separate systems will ultimately develop into one system
consisting of meshed network and radial transmission lines covering whole of
Cambodia. As per the indication available till now, most of the new generating plants
may be owned by IPPs while some transmission lines will be owned by EDC and
others will be owned by many Special Purpose Transmission Licensees. EDC is likely
to be the single buyer and also have agreements with other transmission line owners
to use their transmission system for transmitting electricity to different load centers.

The Distribution Systems supplying electricity to Phnom Penh and surrounding areas
are now connected to the Phnom Penh system. At present no consumer is connected to
the system at HV. In future a large number of Subtransmission and Distribution
systems will be connected to the CTS to deliver electricity to consumers in Cambodia.
With the establishment of bigger industries, in future some consumers may be
connected directly to the CTS at HV or to substations by direct MV feeders.

The safe, reliable and efficient operation of the Cambodia Transmission System,
having large number of participants including NTL, SPTL, Generation Licensees,
Licensees with Embedded Generating Units, External Interconnectors, Distribution
Licensees and consumers,   requires the coordinated operation of all participants. In
this coordinated operation the Control Centers play a very important part. To make
this coordination possible, it is required that the basic rules of operation are
established. This Grid Code establishes the basic rules, requirements, procedures, and
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standards that govern the operation, maintenance, and development of the high
voltage backbone Transmission System in Cambodia.
Electricité Du Cambodge (EDC) has been issued a Consolidated License consisting of
a Generation License, National Transmission License and a Distribution License by
Electricity Authority of Cambodia (EAC).   Condition 1 of chapter 3 of the License
Conditions applicable to the transmission license provides that EDC shall prepare its
Transmission Code, which after approval by EAC, shall be in force at all times and
EDC shall implement and comply with this Transmission Code. EDC shall
periodically review (including upon the request of EAC) the Transmission Code and
its implementation. Revisions to the Transmission Code proposed by EDC shall
require approval of EAC. So according to the License Condition, it is the
responsibility of EDC to manage, review and implement this Grid Code. To make the
Grid Code implement able, it is required that EDC periodically consult other
participants and take their views into consideration. For this purpose, provision has
been made in this Grid Code for a Grid Code Review Panel.

For security and quality supply, the electrical system has to be planned properly based
on studies. The planning of the power sector has the following main components:
a.  Demand Forecast – For planning purposes, not only the demand of whole
system is required, but also the demand on each element of the system to
be planned is required. For planning the transmission system the demand
at each connection point, each substation and each system is required. For
planning of a subtransmission system or distribution system the demand in
each feeder in the subtransmission system or distribution system and each
transformer is required.
b.  Generation and Import Planning – The generation and import planning
will depend on the demand and policy on development and utilization of
generation resources and import of electricity from other countries. The
generation and import planning will have to ensure that sufficient energy
and capacity is available to meet  the demand according to the planning
criteria.
c.   Transmission System Planning – The transmission system planning has
to take into consideration the demand forecast and generation and import
planning and ensure that  quality supply is available to meet the system
demand at each connection point according to the planning criteria.
d.  Subtransmission and Distribution planning – The Subtransmission and
Distribution   system consists of a large number of small systems and each
system is planned based on the connection point, demand on each system
and sources of power, if any, connected to each system.

As per Electricity Law, the Ministry of Industry, Mines and Energy is responsible
for the planning in the power sector. The provision in this regard in the Article 3
of the Electricity Law is:
“The Ministry of Industry, Mines and Energy shall be responsible for setting and
administrating the government policies,  strategies and planning in the power
sector.”

Power system planning needs a lot of data and the originator of the data is best
suited to provide the data. The subtransmission and distribution systems, being
small and simple consisting mostly of radial systems, are easy to plan and can be
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planned as a number of separate systems. But the planning of the transmission
system is complex and a lot more technical. So in the Cambodia context the
planning may be done at two levels. MIME may decide the broad policy defining
the systems to be developed in public sector and by private sector, development
and utilization of generation resources  and import of electricity from other
countries and need not be responsible for the detail planning.

The transmission system, often consisting of parallel meshed paths, needs detailed
studies and has to be planned as an integrated system and hence is to be done by
one agency. In Cambodia, different lines of the transmission system are likely to
be owned by different owners – EDC and other SPTL. Each SPTL will own and
operate only a specified part of the transmission system and hence is neither
equipped nor required by conditions of its license to carry out the planning of the
entire transmission system. On the other hand, it is expected that all or most of the
transmission facilities will be owned or controlled (under transmission
agreements) by EDC and EDC will be in a better position to take up planning of
the entire transmission system. It will have most of the required data and technical
know-how to carry out the planning. As per the provision of the Electricity Law,
MIME will set the policy and will be responsible for the overall planning of the
power sector, preparing the National Plan  for the power sector in Cambodia, but
EDC will be responsible to carry out the detail planning of the entire transmission
system implementing the policy and National Plan of MIME. Hence in this Code,
EDC, the National Transmission Licensee has been given the  responsibilities of
planning the transmission system. The Planning Code provides for the supply of
the required information by Users of the transmission system so that EDC can
undertake the planning and development of the CTS.

The Generation Licensees and HV Customers need connections to the CTS to
deliver electricity and take supply of electricity. The transmission system of one
owner needs to be connected to the adjacent transmission system of another owner
to have a meshed network and to transmit electricity to the load centers. The
Connection Code specifies the minimum technical, design and operational criteria
which must be complied by the Generation Licensee and Customers seeking
connection to the CTS and the transmission  system owners. It also specifies the
procedure to be followed for getting connected to the CTS. The Protection Code
specifies the minimum protection to be provided and  the procedure to enforce
protection coordination. The Safety Co-ordination Code describes the safe
procedures to carry out works at Connection Sites where equipments of more than
one owner are installed.

Different elements of the CTS like generating unit, transmission line, equipment
in substation etc are to be taken out  of service for periodical and emergency
maintenance. These outages are to be planned so that there is minimum possible
interruption to the supply. The Outage Planning Code describes the outage
planning process.

In any grid system, the supply (generation and import) and demand must be
matched at all times. The performance  of the system needs to be monitored
continuously to avoid overloading of any element or operating an element beyond
permissible limits as well as to ensure that quality and reliability of supply is
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maintained. This work is done by the Control Centers. The Control centers carry
out the functions of scheduling and dispatch of generating  plants and imports,
maintain voltage at different nodes and frequency of the system within allowed
limits, and restore the system after any  faults and outages. The Scheduling and
Dispatch Code, Frequency and Voltage Management Code, and Contingency
Planning Code cover these operation procedures. The Control Center requires on
line data and information relating to the operation of the system. The procedures
for the same are described in Metering, Communication and Data Acquisition
Code and Code on Event and Accident Reporting.

GRID CODE

TABLE OF CONTENTS

Chapter Section Description     Page Number

1 GENERAL PROVISIONS …   …   …   …   …   …   …   … …   8
1.1   Grid Code …   …   …   …   …   …   …   …   …   … …    8
1.2   Scope of Application of Grid Code …   …   …   … … …     8
1.3   Grid Code Review and Revisions   …   …   …   … … …   8
1.4   Grid Code Interpretation …   …   …   …   …   … … … …     11
1.5   Derogations …   …   …   …   …   …   …   …   …   …   …   11

2 PLANNING CODE …   …   …   …   …   …   …   …   …   …   14
2.1   Introduction …   …   …   …   …   …   …   …   …   …   …   14
2.2   Objective …   …   …   …   …   …   …   …   …   …   … …   14
2.3   Transmission System Planning Responsibilities   …   … …   15
2.4   Studies for Transmission System Planning …   …   …   …   15
2.5   Planning Standards and Procedures…   …   …   …   …   …     16
2.6   Submission of Planning Data …   … …    …   …   …   …    16
2.7   Historical Demand Data …   …   …   …   …   …   …   …      17
2.8   Forecast Demand Data …   …   …   …   …   …   …   …      17
2.9   Standard Planning Data …   …   …   …   …   …   …   …          18
2.10 Detailed Planning Data …   …   …   …   …   …   …   …      19

3 CONNECTION CODE   …   …   …   …   …   …   …   …  …   21
3.1   Introduction …   …   …   …   …   …   …   …   …   …   …   21
3.2   Objective …   …   …   …   …   …   …   …   …   …   …   21
3.3   Technical, Design and Operational Criteria …   …   …      21
3.4   Procedure for Connection or Modification of a Connection
to the CTS sought by NTL …   …   …   …   25
3.5   Procedure for Connection or Modification of a Connection
to the CTS sought by a User other than the NTL …      26
3.6   Site Responsibility Document …   … …    …   …   …   …   27

4 OUTAGE PLANNING CODE …   …   …   …   …   …    … …   29
4.1   Introduction …   …   …   …   …   …   …   …   …   …   …   29
4.2   Objective …   …   …   …   …   …   …   …   …   …   …   29
4.3   Outage Planning Process …   …   …   …   …   …    …   …   29
4.4   Release of Equipments included in the Outage Plan for
maintenance  …   … …     30

5 SCHEDULING AND DISPATCH CODE …   …   …   …   …   31
5.1   Introduction …   …   …   …   …   …   …   …   …   …   …   31
5.2   Objective …   …   …   …   …   …   …   …   …   …   … …   31
5.3   Scheduling and Dispatch Principles …   …   …   …   … …   31
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5.4   Scheduling and Dispatch Data …   …   …   …   …   … …   32
5.5   Scheduling and Dispatch Procedure …   …   …   …   …   …     33
5.6   Response of Users to Dispatch Instructions …   …   …   …   34

6 FREQUENCY AND VOLTAGE MANAGEMENT CODE …      35
6.1   Introduction …   …   …   …   …   …   …   …   …   …   …   35
6.2   Objective …   …   …   …   …   …   …   …   …   …   …   35
6.3   Methods of Frequency Control …   …   …   …   …   … …   35
6.4   Requirement of Generating Unit Governor System …   …   36
6.5   Load Reduction …   …   …   …   …   …   …   …   …   …   36
6.6   Methods of Voltage control …   …   …   …   …   …   …     36
6.7   Requirement of Demand Power Factor correction and
Capacitor Switching …   … …    …   …   36
6.8   Requirement of Generating Unit AVR Control …   …   …     37

7 CONTINGENCY PLANNING CODE   …   …   …   …   …   …   38
7.1   Introduction …   …   …   …   …   …   …   …   …   …   …   38
7.2   Objective …   …   …   …   …   …   …   …   …   …   … …   38
7.3   Generating Unit with Black Start Capability …   …   … …    38
7.4   Restoration Strategy …   …   …   …   …   …   …   …   …   39
7.5   Restoration Plan …   …   …   …   …   …   …   …   …   …   40
7.6   Responsibilities …   …   …   …   …   …   …   …   …   …     40
7.7   Special considerations …   …   …   …   …   …   …   … …   41

8 SAFETY COORDINATION CODE   …   …   …   …   …   …   42
8.1   Introduction …   …   …   …   …   …   …   …   …   …   …   42
8.2   Objective …   …   …   …   …   …   …   …   …   …   … …   42
8.3   Control Persons …   …   …   …   …   …   …   …   …   …   42
8.4   Procedure …   …   …   …   …   …   …   …   …   …   … …   43
8.5   Special considerations …   …   …   …   …   …   …   … …     43

9 CODE ON REPORTING OF EVENT AND ACCIDENT   …   45
9.1   Introduction …   …   …   …   …   …   …   …   …   …   …   45
9.2   Objective …   …   …   …   …   …   …   …   …   …   … …   45
9.3   Reportable events …   …   …   …   …   …   …   …   … …   45
9.4   Reporting Procedure …   …   …   …   …   …   …   …   …   45
9.5   Major Failure …   …   …   …   …   …   …   …   …   … …     46
9.6   Accident Reporting …   …   …   …   …   …   …   …   … …   46

10 PROTECTION CODE   …   …   …   …   …   …   …   …   …   47
10.1   Introduction …   …   …   …   …   …   …   …   …   …   …   47
10.2   Objective …   …   …   …   …   …   …   …   …   …   … …   47
10.3   General Principles …   …   …   …   …   …   …   …   … …   47
10.4   Protection Coordination …   …   …   …   …   …   …   …   47
10.5   Maximum Time for Fault Clearance …   …   …   …   … …     48
10.6   Protection Requirements …   …   …   …   …   …   …   …   48

11 METERING, COMMUNICATION AND DATA
ACQUISITION CODE   …   …   …   …   50
11.1   Introduction …   …   …   …   …   …   …   …   …   …   …   50
11.2   Objective …   …   …   …   …   …   …   …   …   …   … …   50
11.3   Metering …   …   …   …   …   …   …   …   …   …   … …   50
11.4   Contact Location …   …   …   …   …   …   …   …   … …   50
11.5   Communication Facilities …   …   …   …   …   …   …   …     51

12 GLOSSARY AND DEFINITIONS …   …   …   …   …   … …   53
12.1   Definitions …   …   …   …   …   …   …   …   …   …   …   53
12.2   Abbreviations   …   …   …   …   …   …   …   …   …   …   61

Chapter 1

GENERAL PROVISIONS

1.1 Grid Code

The Grid Code establishes the basic  rules, requirements, procedures and
Standards that govern the  operation, maintenance and development of the High
Voltage backbone Transmission System in Cambodia. The safe, reliable and
efficient operation of the Cambodia Transmission System (CTS) requires the
cooperation of all participants of the electricity industry. It is important that all
Users follow the instructions of the Control Center to ensure reliable operation of
the CTS.

1.2 Scope of Application of Grid Code

The Grid Code is applicable to all Users of the Cambodia Transmission System
including:
a.  The National Transmission Licensee
b.  Special Purpose Transmission Licensees operating High Voltage
Transmission System
c.  Generation Licensees operating Generating Plant connected
directly with the Cambodia Transmission System (CTS) or
operating Embedded Generating Plant connected to
Subtransmission System or Distribution System which is
connected to CTS
d.  Special Purpose Transmission  Licensees operating Medium
Voltage Subtransmission System connected directly with the
Cambodia Transmission System (CTS)
e.  Distribution Licensees operating Distribution System  connected
directly with the CTS
f.  Consumers having their System connected directly with the CTS
g.  External Interconnectors connected to the CTS

The Chapter 3: Connection Code of this Grid Code is also applicable to the Users
intending to get connected to the Transmission System prior to their generating,
transmitting, supplying, or consuming electricity, as the case may be.

1.3 Grid Code Review and Revisions

To keep the Grid Code relevant to the changes and development of the CTS, the
Grid Code will be reviewed periodically, as and when required and when so
directed by EAC. The Users can propose revisions to the Grid Code so that the
Grid Code is capable of meeting its intended purpose. To carry out these reviews
a Grid Code Review Panel headed by the NTL will be formed.

1.3.1  Members of the Review Panel
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The Grid Code Review Panel shall consist of the following members:
a.  An officer from Transmission Department of NTL – Chairman of
the Panel
b.  Another officer from Transmission Department of NTL – Member
Secretary of the Panel
c.  One member from each of the Special Purpose Transmission
Licensees operating HV Transmission System
d.  One member from each of the Generation Licensees connected
directly with the Cambodian Transmission System (CTS) at HV
e.  One member to represent all the HV consumers connected to the
CTS at HV
f.  One member from Distribution Department of EDC as operator of
Subtransmission System and Distribution System connected to the
CTS
g.  One member to represent all SPTL having Subtransmission system
and Distribution Licensees operating MV system connected
directly to the CTS
h.  One member to represent all Generation Licensees under Central
Dispatch delivering electricity at MV

One representative from EAC shall be  invited to attend the meetings of the
Panel as an observer.

The National Transmission Licensee (NTL) shall inform all Users
represented on the Panel in writing of the names and addresses of the Panel
Chairman and Member Secretary at least seven days before the first Panel
meeting and of any subsequent changes in due course.

Each User represented on the Panel shall inform the Panel Member
Secretary in writing of the name and designation of their Panel
representative not less than 3 days before the first Panel meeting and of any
subsequent change in due course.

In the case of sub-paragraphs e, g and h above, the member representing the
group will be selected by the Secretary of the Panel on rotation basis from
the group and the term of the member will be a calendar year. By 1st
December each year the Secretary shall intimate the next member of the
group to nominate its representative to the review panel by 15th December
and on receipt of the name of the new member, the Secretary shall intimate
other members of the Review Panel and EAC about the change of members
to the review Panel for the next calendar year.

Sub-meetings may be held by the NTL with a User to discuss individual
requirements and with groups of Users to prepare proposals for the Panel
meeting.

The Panel may set up sub-committees for detail studies of related problems.

1.3.2  Functions of the Panel

The functions of the Panel are as follows:
a.  To keep the Grid Code and its workings under scrutiny and review
b.  To analyze any major grid disturbances soon after the occurrence
and evolve any consequent revision to the Grid Code.
c.  To consider all proposals made by Users or EAC for amendment to
the Grid Code
d.  To issue guidance on the interpretation and implementation of the
Grid Code.
e.  To examine problems raised by Users.

1.3.3  Rules of Business

The Rules to be followed by the Panel in conducting their business shall be
formulated by the Panel themselves  and shall be approved by EAC. The
Panel will meet at least once in six months. The NTL shall send to EAC
following reports at the conclusion of each Review Meeting of the Panel:
a.  A report on the outcome of such review
b.  Any proposed revisions to the Grid Code for approval of EAC
c.  All written representations or objections from Users arising during
the review.

1.3.4  Procedure for Revision

The Member Secretary of the Review Panel shall present all proposed
revisions of the Grid Code to the Panel for its consideration. The Panel
shall also examine any financial cost involved in the implementation of
the proposed revision and the affected Users. The cost will be borne by the
Users as provided in the relevant agreement. If no provision exists in the
relevant agreement, the Panel should recommend which Users are to bear
the cost for approval by EAC.

All revisions to the Grid Code shall require approval of EAC. The NTL
shall prepare the revised versions of the Grid Code once the revisions are
approved by EAC. The revision number and date of issue shall appear on
relevant pages of the Grid Code. Every change from the previous version
shall be clearly marked in the margin. In addition, a revision sheet shall be
placed at the front of the revised version that lists the number of every
changed Section. The NTL shall send copies of the revised version of Grid
Code to all Users.
1.4 Grid Code Interpretation

1.4.1  In the event that any User requires additional interpretation of the
intention and application of any provision of the Grid Code, it may apply
to the NTL for such interpretation. Provided that the request is reasonable
the NTL shall provide the User with an interpretation of the relevant
provision.

In the event that the User, acting reasonably, considers that an
interpretation provided by the NTL is incomplete, the User may request
additional clarification from the NTL.

1.4.2  In the event that the User, acting reasonably, considers that an
interpretation provided by the NTL pursuant to sub-section 1.4.1 is
unreasonable or incorrect, the User  may require the NTL to refer the
matter to the Grid Code Review Panel for consideration, in which case the
NTL shall refer the matter to the Grid Code Review Panel for
consideration at the next scheduled  meeting of the Grid Code Review
Panel (or in the event that there is insufficient time before the next
scheduled meeting, then at the meeting immediately following the next
scheduled meeting).

1.5 Derogations

1.5.1  If a User finds that it is, or will be, unable to comply with any provision of
the Grid Code, then it shall without delay report such non-compliance to
the NTL and shall, subject to the  provisions of sub-section 1.5.2 make
such reasonable efforts as are required to remedy such noncompliance as
soon as reasonably practicable.

1.5.2  Where the non-compliance is:
a.  with reference to Equipment connected to the CTS and is caused
solely or mainly as a result of a revision to the Grid Code; or
b.  with reference to Equipment which is connected, approved to
connect, or for which approval to connect to the CTS is being
sought,
and the User believes either that it would be unreasonable (including cost
and technical considerations) to require it to remedy such non-compliance
or that it should be granted an  extended period to remedy such non-
compliance, it shall promptly submit to EAC a request for a derogation
from such provision and shall provide the NTL with a copy of such a
request.

1.5.3  A request for derogation from any provision of the Grid Code shall
contain:

a.  the version number and date of the Grid Code which includes the
provision against which the non-compliance or predicted non-
compliance is identified;
b.  identification of the Equipment in respect of which a derogation is
sought and, if relevant, the nature and extent to which the non-
compliance exists;
c.  identification of the provision with which the User is, or will be,
unable to comply;
d.  the reason for the non-compliance; and
e.  the date by which compliance will be achieved (if remedy of the
noncompliance is possible).

1.5.4  If the NTL finds that it is, or will be, unable to comply with any provision
of the Grid Code, then it shall, subject to the remaining provisions of this
Section 1.5 make such reasonable efforts as are required to remedy such
non-compliance as soon as reasonably practicable.

1.5.5  If the NTL believes either that it would be unreasonable (including cost
and technical considerations) to require it to remedy such non-compliance
or that it should be granted an  extended period to remedy such non-
compliance, it shall promptly submit to EAC a request for a derogation
from such provision along with the information  set out in sub-section
1.5.3.

1.5.6  On receipt of any request for derogation, EAC shall consider such request
and provided that EAC considers that the grounds for the derogation are
reasonable, then EAC shall grant such derogation unless the derogation
would, or it is likely that it would, have a material adverse impact on the
security and stability of the CTS or impose unreasonable costs on the
operation of the CTS or on other Users. In its consideration of a
derogation request by a User, EAC may contact the relevant User and or
the NTL to obtain clarification of the request, or to obtain further
information regarding the request, or to discuss changes to the request.
The NTL may also contact the relevant User to obtain clarification of the
request, or obtain further information regarding the request, or to discuss
changes to the request. The User shall respond to all such requests without
undue delay.

1.5.7  Derogations from any provision of the Grid Code shall contain:
a.  the version number and date of the Grid Code which includes the
provision against which the derogation applies;
b.  identification of the provision with which the derogation applies;
c.  identification of the Equipment in respect of which a derogation
applies and, if relevant, the nature and extent to which the
derogation applies including alternate compliance provisions;
d.  the reason for the non-compliance requiring derogation;
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e.  the date by which the derogation ends if compliance will be
achieved, or by which such derogation expires.

1.5.8  To the extent of any derogation granted in accordance with this Section
1.5, the NTL and/or the User (as the case may be) shall be relieved from
its obligation to comply with the applicable provision of the Grid Code
and shall not be liable for failure to so comply but shall comply with any
alternate provisions as set forth in the derogation.

1.5.9  The NTL shall:
a.  keep a register of all derogations which have been granted,
identifying the User and Equipment in respect of whom the
derogation has been granted, the relevant provision of the Grid
Code and the Grid Code version number, the period of the
derogation and the extent of compliance to the provision; and
b.  on request from any User, provide  a copy of such register of
derogations to such User

1.5.10 Where a material change in circumstance has occurred, a review of any
existing derogations, and any derogations under consideration, may be
initiated by EAC by itself or at the request of the NTL, or Users.

Chapter 2

PLANNING CODE

2.1 Introduction

Proper and desired development of the CTS will involve its reinforcements and
extension from time to time which will arise for a number of reasons, including
but not limited to the following.
a.  Extension of the Cambodia Transmission System from time to
time for providing Grid supply to new areas.
b.  The introduction of a new Connection Point or the modification of
an existing Connection Point between a User System and the
Cambodia Transmission System required for various reasons,
including but not limited to connection of a new power plant,
connection of a new load, change in the capacity of a power plant
or change in the quantum of load already connected to the CTS or
modification of a User System.
c.  Development on a User System already connected to the
Cambodia Transmission System.
d.  A general increase in system capacity to remove operating
constraints and maintain standards of security.
e.  Stability considerations.
f.  Cumulative effect of any of the above.

The time required for the design and development of the reinforcement or
extension of the Cambodia Transmission System or User System is appreciable
and will depend on the type and extent of the work. Hence advance timely action
is required for the planning of the system to allow adequate time for all aspects of
development of a project. The information required for the planning and design of
the system also should be available in advance. To this effect the Planning Code
imposes a time scale, for actions to be taken for planning of the system and the
exchange of necessary information required for planning.

2.2 Objective

The objectives of the Planning Code are:
a.  To specify the responsibilities of the NTL and other Users in
planning the development of the Cambodia Transmission System;
b.  To specify the technical studies and planning procedures that will
ensure the safety, security, reliability and stability of the Cambodia
Transmission System;
c.  To specify the planning data required for a User seeking a new
connection or a modification of  an existing connection to the
Cambodia Transmission System; and
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d.  To specify the data requirements in planning the development of
the Cambodia Transmission System.

2.3 Transmission System Planning Responsibilities

2.3.1  The National Transmission Licensee  is responsible for planning the
Cambodia Transmission System. It shall take the National Plan on Power
Sector prepared by MIME as base for planning of the Cambodia
Transmission System.

2.3.2  The Users of the CTS including Special Purpose Transmission Licensees,
Generation Licensees are responsible for submission of the required
planning data to enable the National Transmission Licensee to maintain
the data bank required for grid planning.

2.4 Studies for Transmission System Planning

2.4.1  The CTS should be evolved based on detailed power studies. Subject to
Section 2.4.2, the NTL may conduct some or all of the following studies,
as it decides to be necessary:

a.  Power Flow Studies – Power flow studies are performed to
evaluate the behavior of the transmission system for the existing
and planned transmission facilities under forecasted maximum and
minimum load conditions and to study the impact on the
transmission system of the connection of new Generating Plant,
loads or transmission lines. For new transmission lines, the load
condition that produces maximum power flows through the
existing and new lines are identified and evaluated.

b.  Short Circuit Studies – Short circuit studies are performed to
evaluate the effect on transmission system equipment of the
connection of new Generating Plants, transmission lines and other
facilities that result in increased fault duties for transmission
system equipment. These studies  identify the equipment that can
be permanently damaged during fault condition due to current
exceeding the design limit of the equipment.

c.  Stability Studies

Transient stability studies are performed to verify the impact of the
connection of new Generating Plants, transmission lines and
substations and other changes in transmission circuit
configurations on the ability of the Grid to seek a stable operating
point following a transient disturbance. This study simulates the
outage of critical grid facilities such as major lines and generating
units. This study may be performed only when connection of major
facilities are done.

Voltage stability studies are performed periodically to determine if
the Grid is vulnerable to voltage collapse under heavy loading
condition. A voltage collapse can  proceed very rapidly if the
ability of System’s Reactive Power supply to support system
voltages is exhausted. The study identifies safe Grid operating
conditions where vulnerability to voltage collapse can be avoided
until solutions are implemented.

Steady state oscillatory stability studies are performed to determine
if the Grid is vulnerable to steady state stability problems. Such
problems occur on heavily loaded systems, where small
disturbances may cause steady-state oscillations that can lead to
major disturbances.

d.  Electromagnetic Transient Studies – Electromagnetic transient
studies are performed to determine switching/ temporary over
voltages which can affect equipment insulation, the thermal
dissipation capacity or the clearing capacity of the protection
devices.

2.4.2  However, when directed by EAC, the NTL shall carry out the studies
stated in the direction.

2.5 Planning Standards and Procedures

The CTS shall be planned in accordance with the Transmission System planning
standard for Cambodia and the system should confirm to the Technical Standards
issued by MIME.

2.6 Submission of Planning Data

2.6.1  Any User applying for connection or a modification of an existing
connection to the CTS shall submit to the NTL the relevant Standard
Planning Data specified in Section 2.9 and the Detailed Planning Data
specified in Section 2.10, in accordance with the requirement prescribed in
Section 3.5 of Connection Code.

2.6.2  All Users shall submit annually to the NTL by 1st
July the Standard
Planning Data and Detailed Planning Data indicating the current position
and any changes expected in the next seven years.

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2.6.3  All Users having a load demand shall submit annually to the NTL by 1st

July the Forecast Demand Data specified in Section 2.8 for each
Connection Point for the next seven years.

2.6.4  All SPTL shall submit monthly to the NTL the Historical Demand Data
specified in Section 2.7 for each Connection Point, each voltage level at
the substation during the previous month by 5th
of each month. The NTL
shall collect this data relating to the Transmission System under its
control.

2.6.5  The NTL shall consolidate and maintain the planning data. The NTL shall
collate and process the planning data submitted by the Users into a
cohesive forecast and use this in preparing the statement on system
available capacity as provided in  its license conditions (Chapter 5,
Condition 1.2 of license issued to EDC).

2.7 Historical Demand Data

2.7.1  The SPTL shall provide to the NTL the actual monthly Energy, maximum
and minimum Demand in MW and corresponding reactive Demand in
MVAr during the month for each connection point and each voltage level
of the substation under its control. The SPTL shall also provide the NTL
with actual hourly load profile for a typical weekday, weekend and
holiday.

2.7.2  The NTL shall maintain a database  of hourly demand for each separate
System in its Control Center.

2.8 Forecast Demand Data

2.8.1  All Users having a load demand shall provide to the NTL with its Energy
and Demand Forecast at each Connection Point for the next seven years by
1st
July each year. The forecast data for the first year shall include monthly
Energy and Demand forecasts, with forecasted hourly load profiles for a
typical weekday, weekend and holiday.  The forecast data for the
remaining six years shall include  only the annual Energy and Demand
forecast. The forecast data shall be the total Energy and Demand
requirement at the Connection Point including losses in the User system.

Users having Embedded Generating Plant shall provide the net values of
Energy and Demand forecast after deductions to reflect the output of
Embedded Generating Plants. Such deductions shall be stated separately in
the Forecast Demand Data.

2.8.2  The NTL will use the above information in a reasonable manner and
prepare a demand forecast for the next seven years for each Connection
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Point, for each voltage level at each substation and for each separate Grid
by 31st
October each year.

2.9 Standard Planning Data

The User shall provide the electrical diagram of its system and information about
each of the facility as stated in this Section.

2.9.1  User System and Connection Point Data
The User shall provide electrical  diagram for the User System and
Connection Point indicating the arrangement, ratings etc of the following:
a.  Equipments such as Generating Units, power transformers, circuit
breakers etc;
b.  Electric lines and cables
c.  Substation bus arrangements
d.  Grounding arrangements
e.  Switching facilities
f.  Phasing arrangements.

2.9.2  Generating Unit Data
The following information shall be provided for each Generating Unit of
each Generating Plant including Embedded Generating Plant:
a.  Rated capacity (MVA and MW)
b.  Rated Voltage (kV)
c.  Type of Generating Unit
d.  Expected mode(s) of running
e.  Direct axis sub-transient reactance (percent).

2.9.3  HV lines and cables
The following information shall be provided for the HV lines and cables
from the Connection Point to the User System substation.
a.  Rated voltage (kV)
b.  Positive sequence resistance and reactance (ohm)
c.  Positive sequence shunt susceptance (ohm-1
)
d.  Zero sequence resistance and reactance (ohm)
e.  Zero sequence shunt susceptance (ohm-1
)

2.9.4  Power Transformer
The following information shall be provided for the power transformers in
the User System.
a.  Rated capacity (MVA)
b.  Rated voltage ratio (kV)
c.  Winding arrangement
d.  Positive sequence resistance and reactance at maximum, minimum
and normal tap
e.  Zero sequence reactance for three-legged core type transformer
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f.  Tap changer range, step size and type (on-load or off-load)
g.  Basic lightning impulse insulation level (kV)
2.9.5  Switchgear
The following information shall be provided for the switchgear including
circuit breakers, load break switches and disconnect switches at the
Connection Point and at the substation of the User.
a.  Rated Voltage (kV)
b.  Rated current (A)
c.  Rated symmetrical RMS short-circuit current (kA)
d.  Basic lightning impulse insulation level (kV)

2.9.6  System Grounding
The following information shall be provided for the system grounding.
a.  Rated capacity
b.  Impedances of the grounding equipment

2.9.7  Reactive Power compensation equipment
The following information shall be provided on Reactive Power
compensation equipment at the Connection Point and/or at the substation of
the User System.
a.  Rated capacity (MVAr)
b.  Rated Voltage (kV)
c.  Type (e.g., shunt inductor, shunt capacitor, static VAr compensator
etc)
d.  Operation details (e.g., fixed or switched)
e.  If switched – control details (automatic or manual)
f.  If automatic control – details of setting
g.  If it has Black Start capability.

2.10  Detailed Planning Data

2.10.1  Generating Unit Data
The following additional information shall be provided for the Generating
Units of each Generating Plant.
a.  Derated capacity (MW) if applicable
b.  Additional capacity (MW) obtainable in excess of declared
capacity, if any
c.  Minimum Stable Loading (MW)
d.  Reactive Power Capability Curve
e.  Stator armature resistance
f.  Direct axis synchronous, transient and sub-transient reactance
g.  Quadrature axis synchronous, transient and sub-transient
reactances
h.  Turbine and Generating Unit inertia constant (MWsec/MVA)
i.  Rated field current (A) at rated MW and MVAr output and at rated
terminal voltage
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j.  Short circuit and open circuit characteristic curves

2.10.2  Data for Excitation Control system of Generating Unit
a.  DC gain of excitation loop
b.  Rated field voltage
c.  Maximum field voltage
d.  Minimum field voltage
e.  Maximum rate of change of field voltage (rising)
f.  Maximum rate of change of field voltage (falling)
g.  Details of excitation loop described in diagram form showing
transfer functions of individual elements
h.  Dynamic characteristics of over-excitation limiter and under-
excitation limiter.

2.10.3  Data for speed-governing system for each reheat steam Generating Unit
a.  High pressure governor average gain (MW/Hz)
b.  Speeder motor setting range
c.  Speed drop characteristic curve
d.  High pressure governor valve time constant
e.  High pressure governor valve opening limits
f.  High pressure governor valve rate limits
g.  Re-heater time constant (Active Energy stored in re-heater)
h.  Intermediate pressure governor average gain (MW/Hz)
i.  Intermediate pressure governor setting range
j.  Intermediate pressure governor valve time constant
k.  Intermediate pressure governor valve opening limits
l.  Intermediate pressure governor valve rate limits
m.  Details of acceleration sensitive  elements in high pressure and
intermediate pressure governor loop
n.  A governor block diagram showing the transfer  functions of
individual elements

2.10.4  Data for speed-governing system for each non-reheat steam, gas turbine,
geothermal and hydro Generating Unit
a.  Governor average gain
b.  Speeder motor setting range
c.  Speed drop characteristic curve
d.  Time constant of steam or fuel  governor valve or water column
inertia
e.  Governor valve opening limits
f.  Time constant of turbine

Chapter 3

CONNECTION CODE

3.1 Introduction

As the CTS is developed, extended and or strengthened, more transmission lines,
Generating Plant and load will be connected to the existing system. For safe and
efficient operation of the system, the two systems at the Connection Point have to
comply with certain technical, design and operational conditions. Connection
Code specify the technical, design and operational criteria which must be
complied by any User connected to the CTS.

3.2 Objective

The objectives of the Connection Code are:
a.  To specify the minimum technical, design and operational criteria
b.  To ensure that the basic rules for connection to the CTS or to a
User System are fair and non-discriminatory for all Users of the
same category
c.  To list and collate the data required by the Transmission System
Owner/NTL from each category of User and to list the data to be
provided by the  NTL to each category of User
d.  To ensure that any new connection shall not impose any adverse
effects on existing Users, nor shall a new connection suffer
adversely due to existing Users.

3.3 Technical, Design and Operational Criteria

3.3.1  CTS Performance Characteristics
The NTL shall ensure that the CTS will comply with the following
operational criteria.
a.  System Frequency shall be nominally 50 Hz and shall be
controlled within the limits of 49.5 Hz – 50.5 Hz unless exceptional
circumstances prevail. The System Frequency could fall to 47 Hz
or rise to 52 Hz in exceptional circumstances.
b.  System Voltage at the Connection Point will normally remain
within the operating range stated in the table below unless
exceptional conditions prevail.
Nominal Voltage  Higher Limit  Lower Limit
230 kV  245 kV  207 kV
115 kV  123 kV  103.5 kV
22 kV  24 kV  19.8 kV

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Following major System faults,  the maximum over voltage of
+15% for the 230 kV system and +20% for the 115 kV system may
occur but the duration shall not exceed 15 minutes unless
exceptional conditions prevail. Under fault conditions, voltage may
collapse transiently to zero at the point of fault until the fault is
cleared.

c.  The maximum total levels of harmonic voltage distortion and the
total demand distortion of the current on CTS at a Connection
Point under normal operating conditions and under both planned
and unplanned outage conditions (other than for infrequent short
duration peaks) shall be:

Harmonic Voltage Distortion
Individual Distortion  Voltage Level
(kV)
Total Harmonic
Distortion  Odd  Even
115-230  2.5%  1.5%  1%
22  3%  2%  1%

Harmonic Current Distortion
Individual Distortion  Voltage Level
(kV)
Total Demand
Distortion  Odd  Even
115-230  2.5%  2%  0.5%
22  5%  4%  1%

The Equipments connected to the CTS should be capable of
withstanding the above harmonic distortions.

d.  Under normal operating and planned outage conditions, the
maximum negative phase sequence component of the phase
voltage on CTS shall not exceed 1% other than for infrequent short
duration peaks with a maximum value of 2%.

e.  The short circuit current level at a point on the CTS shall be below
the levels stated below:
40 kA on the 230kV system
31.5 kA on the 115kV system
12.5 kA on the 22kV system

3.3.2  User System General Provisions

a.  Equipment Standard
All Equipment at the Connection Point shall comply with the
Technical Standards issued by MIME. For standards not provided
in the Technical Standards, the Equipments shall comply with the
IEC Standards. All Equipment should be capable of operating
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under or protected for the system conditions defined in Section
3.3.1 above.

b.  Protection, Communication, Telemetry
The User System should comply with the provisions given in
Chapter 10 – Protection Code and Chapter 11 – Metering,
Communication and Data Acquisition Code.

c.  Harmonics
Users shall ensure that their System shall not cause the harmonics
in the CTS to exceed the limits specified in Section 3.3.1(c).

d.  Fault rating of equipment
The fault rating of any equipment shall not be less than the fault
level in that part of the network at any time over the life of the
equipment.

3.3.3  Generating plant

All Generating Units must be capable of supplying rated Active
Power output at any point between the limits 0.85 power factor
lagging and 0.95 power factor leading at the Generating Unit
terminals, unless otherwise agreed by the NTL. The short circuit
ratio of the Generating Units shall be not less than 0.5 unless
otherwise agreed by the NTL.

A Generating Unit must be capable of continuously supplying its
rated Active Power output at the Generating Unit terminals within
the System Frequency range 49.5 to 50.5 Hz. Any decrease of
Active Power output occurring in  the frequency range 49.5 to 47
Hz should not be more than pro rata with frequency.

Design of Generating Unit must ensure continuous operation of the
Generating Units for Frequency range of 47.5 to 52 Hz and
operation for a period of 20 seconds each time the frequency is
between 47 and 47.5 Hz.

The Active Power output at the Generating Unit terminals under
steady state conditions  should not be affected by voltage changes
in the normal operating range specified in Section 3.3.1.b. The
Reactive Power output at the Generating Unit terminals under
steady state conditions and at rated Active Power should be fully
available within the range ±5% of nominal grid system voltage at
the Connection Point.
Each Generating Unit must be capable of contributing to, in a
manner satisfactory to the NTL, frequency and voltage control by
modulation of Active Power and Reactive Power supplied to the
CTS.

Each Generating Unit must be fitted with a fast acting proportional
turbine speed governor to provide frequency control under normal
operational conditions in accordance with Chapter 6: Frequency
and Voltage Management Code. Where a Generating Unit
becomes isolated from the rest of the CTS but is still supplying
consumers, the speed governor must also be able to control the
Frequency between 47.5Hz and 52Hz.

A continuously-acting fast-response automatic excitation control
system is required to control the Generating Unit voltage without
instability over the entire operating range of the Generating Unit.
The control system may be required to include power system
stabilizing equipment if required by the NTL.

On-load tap changing facilities  are required on Generating Unit
transformer for dispatch of Reactive Power. The transformer
voltage ratio, tapping range and step sizes must be such that the
reactive requirements specified in Paragraph 4 above of this
Subsection are fully complied with.
The higher voltage windings of  the Generating Unit transformer
connecting a Generating Unit to the CTS at voltages of 115 kV and
above shall be star connected with the star point earthed in
accordance with IEC standards.

The NTL shall be entitled to acquire such operational metering,
control parameter and Equipment data as it reasonably requires for
the purposes of managing the CTS.

3.3.4  Distribution Licensees and Consumers connected directly to CTS

a.  Under-frequency relays
If required by NTL, the Users with load shall provide suitable
under-frequency relays for automatic disconnection of demand
blocks of predetermined sizes when the System Frequency falls
below predetermined values.

b.  Neutral Earthing
The upper voltage winding of the three phase transformers
connected to CTS at voltages of  115 kV and above shall be star
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connected with the star point  connected to earth as per IEC
standards.

3.3.5  Maintenance Standard
All Equipments at the Connection Site shall be operated and maintained in
accordance with Prudent Utility Practice and in a manner that shall not pose
a threat to the safety of any personnel or cause damage to the Equipment of
the Transmission System Owner or the User.
The User shall maintain a log containing the test results and maintenance
records relating to its Equipment at the Connection Site and shall make this
log available when requested by the Transmission System Owner.
The Transmission System Owner shall maintain a log containing the test
results and maintenance records relating to its Equipment at the Connection
Site and shall make this log available when requested by the User.

3.4 Procedure for Connection or Modification of a Connection to the CTS sought
by NTL

3.4.1  The NTL, seeking to establish a new connection or modification to an
existing connection to the Transmission System, shall first evaluate the
impact of the proposed connection or modification to the existing
connection. For this, the NTL may carry out some or all of the planning
studies, it considers necessary, out of the studies described in Section 2.4.
The NTL shall not submit an application for connection or a modification
to an existing connection, if the studies show that the proposed connection
or a modification to an existing connection will result in the Degradation
of the CTS.

3.4.2  If the studies show that the proposed connection or a modification to an
existing connection will not result in the Degradation of the CTS, the NTL
shall submit the following report, data and undertaking along with an
application to the TS Owner:
a.  Report stating purpose of proposed connection or modification,
details of Connection Point, description of Equipment to be
connected or of the modification to the existing Equipment.
b.  Construction schedule and target completion date
c.  Confirmation that the prospective installation complies with the
Technical Standards of Cambodia

3.4.3  Normally, the TS owner shall inform the NTL within 30 days of receipt of
the application complete with all information whether the proposed
connection or modification is acceptable or not. If the nature of
complexity of the proposal is such that the above time limit is not
adequate, the TS owner shall intimate the NTL and EAC about the extent
of further time required for intimating the decision.

3.4.4  The intimation of acceptance of the proposal shall include an offer to sign
a Connection Agreement or an Amended Connection Agreement within a
specified time limit which shall not  be less than 60 days. A Connection
Agreement shall include, as appropriate, within its term and conditions the
following:
a.  A condition requiring all parties to comply with the Grid Code
b.  Details of connection
c.  Commercial arrangements
d.  Details of information to be submitted by the NTL prior to the date
of commissioning including protection arrangement and settings,
Site Responsibility Document and safety rules and test and
commissioning schedule
e.  Details of any capital related payments
f.  Guide lines on protection, communication etc
In case the above provisions are already included in an agreement such as
power purchase agreement, supply agreement, transmission/ wheeling
agreement, it may not be necessary to sign a separate Connection
Agreement.

3.5 Procedure for Connection or Modification of a Connection to the CTS sought
by a User other than the NTL

3.5.1  Any User, other than the NTL, seeking to establish a new connection or
modification to an existing connection to the Transmission System shall
submit the following report, data  and undertaking  along with an
application to the NTL:
a.  Report stating purpose of proposed connection or modification,
details of Connection Point, description of Equipment to be
connected or modification to the existing Equipment.
b.  Construction schedule and target completion date
c.  Standard Planning Data
d.  Confirmation that the prospective installation complies with the
Technical Standards of Cambodia
e.  All other information as the  NTL may reasonably require for
evaluating the application.

3.5.2  The NTL shall evaluate the impact on the CTS of the proposed connection
or modification to the existing connection. The NTL shall specify if any of
the planning studies described in Section 2.4 are required to be carried out
afresh to evaluate the impact of the proposed connection or modification
to the existing connection. The User shall indicate whether it wishes the
NTL to undertake additional technical studies. The User shall bear the cost
of all the studies carried out to  evaluate the impact. The NTL may
disapprove an application for connection or a modification to an existing
connection, if the studies show  that the proposed connection or a
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modification to an existing connection will result in the Degradation of the
CTS.

3.5.3  If the studies show that the proposed connection or a modification to an
existing connection will not result in the Degradation of the CTS, the NTL
shall consult the TS owner on the proposed User Development and work
out the details of any and all works required to be carried out by the TS
owner and decide if the proposal is acceptable. The NTL in consultation
with the TS owner shall work out the capital-related payments, if any,
arising from the works to be carried out by the TS owner.

3.5.4  Normally, the NTL shall inform the User within 90 days of receipt of the
application complete with all information whether the proposed User
Development is acceptable  or not. If the nature  of complexity of the
proposal is such that the above time limit is not adequate, the NTL shall
intimate the User and EAC about the extent of further time required for
intimating the decision.

3.5.5  The intimation of acceptance of the proposal shall include an offer to sign
a Connection Agreement or an Amended Connection Agreement within a
specified time limit which shall not be less than 60 days. If the TS owner
is a SPTL and not the NTL, the Connection Agreement shall be a tripartite
agreement between the NTL, TS owner and User seeking the User
Development. A Connection Agreement shall include, as appropriate,
within its term and conditions the following:
a.  A condition requiring all parties to comply with the Grid Code
b.  Details of connection , technical requirements with specific
reference to reactive power compensation, operation of Generating
Units, if any, and commercial arrangements
c.  Time limit for submission of Detailed Planning Data
d.  Details of information to be submitted by the User prior to the date
of commissioning including additional equipment data, protection
arrangement and settings, information required to prepare the Site
Responsibility Document and safety rules and test and
commissioning procedures
e.  Details of any capital related payments
f.  Guide lines on protection, communication etc

3.6 Site Responsibility Document

3.6.1  A Connection Site may be owned either by the TS owner or a User
seeking connection to the CTS. For every connection to the CTS a Site
Responsibility Document shall be prepared and issued by the TS owner at
least two weeks before the date of commissioning of the connection. The
Site Responsibility Document shall state the following for each
equipment installed at the Connection Site:
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a.  The ownership of equipment
b.  The responsibility of control equipment
c.  The responsibility for maintenance of the equipment
d.  The responsibility for operation of equipment
e.  The manager of the site
f.  The responsibility for all matters relating to persons at site.
The User shall provide the information  that will enable the TS owner to
prepare the Site Responsibility Document.
The Site Responsibility Document shall be a part of the Connection
Agreement.

3.6.2  The owner of the Connection Site shall provide reasonable access and
other required facilities to the User whose equipments are installed or are
to be installed at the Connection Site for installation, operation, and
maintenance etc of these equipments.

Chapter 4

OUTAGE PLANNING CODE

4.1 Introduction

In the process of power supply, all equipment put in operation in the power
system needs to be taken out of service for some time for checking, maintenance,
and repair. Outage Planning is concerned with the co-ordination of the release of
the Generating Units, External Interconnections and Transmission System for
construction, repair and maintenance purposes.

4.2 Objective

The objective of Outage Planning is to define the process, which will allow
harmonizing the outages of all Generating Units, Generating Plants, External
Interconnections and the CTS while maintaining system security to the extent
possible.

4.3 Outage Planning Process

4.3.1  Users, having generation and/or transmission, shall provide the NTL with
their provisional Outage Plan for the next year by 1st
July each year. The
following information shall be included in the provisional Outage Plan:
a.  Identification of the equipment and MW capacity involved
b.  Reasons for the proposed outage
c.  Expected duration of the outage
d.  Preferred start date for the outage
e.  If there is flexibility in dates, the earliest start date and the latest
completion date.

4.3.2  In preparing the Outage Plan, the NTL shall endeavor to accommodate the
User’s request for the dates, while taking into account the requirements of:
a.  Demand Forecast
b.  The needed cold reserve (back-up reserve)
c.  Available generation capacity and  exchange of power with other
systems
d.  Forecast of hydrological reliability
e.  System Security, to the extent possible

4.3.3  The NTL shall produce a coordinated generation and transmission Outage
Plan and shall provide the User a copy of the User’s approved Outage Plan
by 30th
September each year.

4.3.4  If the User is not satisfied with the Outage Plan allocated to its Equipment,
it shall notify the NTL by 10th
October explaining its concerns and
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proposing changes to the Outage Plan. The NTL and User shall discuss
and resolve the problem. The Outage  Plan shall be revised by the NTL
based on the resolution of the User’s  concerns before 20th
October each
year.

4.3.5  If the Outage Plan is likely to affect the supply to a User connected to and
receiving supply from the CTS, the NTL will intimate each relevant User
by 20th
October each year about the probable period and the manner in
which the supply of electricity to the User is likely to be affected during
next year. The relevant User may  use the information to develop the
Outage Plan of its System. It may be noted that the actual period and the
manner in which the supply is affected may change during implementation
of the Outage Plan.

4.4 Release of Equipments included in the Outage Plan for maintenance

Notwithstanding provision in any approved Outage plan, no transmission circuit
or Generating Unit shall be removed from service by the User without specific
release from the Control Center.

Once an Outage has commenced, if any delay in restoration is apprehended, the
Control Center or User concerned shall inform the other party promptly together
with revised estimation of restoration time.

Chapter 5

SCHEDULING AND DISPATCH CODE

5.1 Introduction

This Chapter specifies the procedure to be adopted for the scheduling and
dispatch of Generating Units to meet demand and to achieve an economic
operation while maintaining power quality, stability and the stability and security
of the CTS.

5.2   Objective

The objectives of Scheduling and Dispatch are:
a.  To define the operational criteria for the preparation of the
Generation Schedule and issuance of Dispatch Instructions
b.  To specify the process and requirements for preparation of the
Generation Schedule
c.  To specify the Central Dispatch process.

5.3 Scheduling and Dispatch Principles

5.3.1  Operating Margin
The Operating Margin shall include the generating capacity for the
Frequency Regulating Reserve, which is required to respond to changes in
Demand during normal conditions and the Contingency Reserve needed to
respond to a sudden reduction in generation during emergency conditions.
The Frequency Regulating Reserve and Contingency Reserve shall be
allocated to strategically located Generating Plants to keep the frequency
within limits.
However, when a major portion of the demand is met from imports from
other systems, the capacity of the Operating Margin to be provided from
generating capacity connected to CTS may be decided by the Control Center
depending on the real situation.

5.3.2   Scheduling and Dispatch Criteria
The Control Center shall endeavor to take into account the following
operational criteria in Scheduling and Dispatch:
a.  The Synchronized generating capacity shall be sufficient to match,
at all times, the forecasted Demand and the required Frequency
Regulating Reserve and Contingency Reserve to ensure the
Security and Reliability of the CTS
b.  The availability of Generating Units at strategic locations so that
the CTS will continue to operate in normal state even with the loss
of the largest Generating Unit or the power import from a single
interconnection, whichever is larger
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c.  The technical and operational constraints of the CTS and the
Generating Units
d.  The Security and Stability of the CTS

The Control Center shall take into account the following factors in preparing
the Generation Schedule:
a.  The registered parameters of the Generating Units
b.  The availability from External Interconnections
c.  The requirement of Reactive Power for voltage control
d.  The need to provide an Operating Margin for frequency control
e.  The availability of Ancillary Services
f.  Bilateral contracts between Generation Licensees and Users
g.  Merit Order Dispatch

The Control Center shall take into account the  following factors in
Dispatching Generating Units:
a.  The Generation Schedule
b.  The Demand from the Users
c.  Transmission System restraints
d.  System Loss
e.  The requirement for Ancillary Services
f.  Merit Order Dispatch

5.4 Scheduling and Dispatch Data

5.4.1  Generation Licensees
All Generation Licensees connected directly to CTS and Generation
Licensee operating Embedded Generating Plant subject to Central Dispatch
shall provide the hourly MW and MVAr availability of all Generating Units
for the next day (00.00 – 24.00 hours) to the Control Center by 10.00 hrs on
each day.

In working out the MW and MVAr availability, the Generation Licensees
operating Hydro Generating Units shall  take into account their respective
reservoir levels and any other restrictions and shall report the reservoir level
and restrictions to the Control Center.

The User having Embedded Generating Plant not subject to Central Dispatch
connected to its system shall provide the hourly MW and MVAr net
injection to the transmission system for the next day (00.00 – 24.00 hours) to
the Control Center by 10.00 hrs on each day.

The Generation Licensees shall, without delay, notify the Control Center of
any change in the declared availability.

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5.4.2  External Interconnectors
External Interconnectors shall provide the hourly MW and MVAr export and
import or agreed availability for the next day to the Control Center by 10.00
hrs on each day.

In the event of no intimation from an External Interconnector, the Control
Center shall make an estimate of the export and import.

5.4.3  Other Users
In addition to its Demand Forecast as provided in Section 2.8, all Users
having a load demand shall notify the Control Center, without delay, of any
constraints or development on the User System which may have substantial
effect on its Demand along with its likely duration, which the Control Center
needs to take into account in Scheduling and Dispatch.

5.5 Scheduling and Dispatch Procedure

5.5.1  The Control Center shall prepare a cohesive forecast of hourly System
Demand, which shall include the System Loss.

5.5.2  The Control Center shall prepare a Merit Order Table considering the
incremental cost of Generation/Import according to the PPAs. If the price
for any Generating Plant/source is different for different blocks of time
during the day, the Merit Order Table  shall be prepared for each such
blocks of time so that the correct Merit Order is reflected in the Table. In
the event two or more Generating  Units having the same price, the
Generating Unit that will result in a smaller System loss will be given
higher merit.

5.5.3  All Generation Licensees including the licensees operating Embedded
Generating Plants under Central Dispatch and External Interconnectors
shall provide the hourly MW and MVAr availability as provided in
Section 5.4.

5.5.4  The Control Center shall use the Merit Order Table to match the hourly
demand requirement with the available capacity of Generating Plant in
developing the Generation Schedule  for the next day. In deciding the
Generation Schedule, the Control Center shall also take into consideration
the following factors:
a.  Transmission constraint from time to time
b.  The need to provide operating margins and reserves required to be
maintained
c.  Minimum Stable Loading of Generating Units (Technical limits of
operation of Generating Units)
d.  Scheduled daily water usage of hydroelectric Generating Plants
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e.  Overall economy for the cost of power

If the available capacity is not sufficient to meet the demand forecast and
reserves, discreet load blocks equal to the amount of shortfall in capacity
shall be identified for load shedding and the affected Users should be
intimated about the identification and  amount of load and duration of the
load shedding.

The Generation Schedule shall indicate the hourly output of each Generating
Unit/Plant and hourly injection by Embedded Generating Plant/ External
Interconnectors for the next day. It shall also indicate the Generating Units
that are providing specific Ancillary Services. The generation Schedule for
the next day shall be issued by the Control Centre normally by 16:00 hours.

5.5.5  The Dispatch Instruction may be issued at any time after issue of the
Generation Schedule. If required, a Dispatch Instruction may be issued
even before issue of the Generation Schedule for the next day.

5.5.6   The Dispatch Instruction shall contain the following:
a.  The specific Generating Unit to which the instruction applies
b.  The MW and MVAr output required
c.  Start and synchronizing time of Generating Units
d.  Desynchronizing or shutdown time of Generating Units
e.  The Dispatch Instruction issuance time.

The Dispatch Instruction shall be recorded in a log book or other means of
recording.

The Control Center shall issue the Dispatch Instruction to a Generation
Licensee through an appropriate  means of communication. Written
confirmation shall be issued promptly for all oral instructions through
appropriate means of communication.

5.5.7  The Dispatch Instruction shall remain valid unless superceded by another
Dispatch Instruction. The Control Center can revise a dispatch instruction
any time as required.

5.6 Response of Users to Dispatch Instructions

The User shall acknowledge immediately and comply with the Dispatch
Instruction including oral instructions.

In the event there is any problem in carrying out the Dispatch Instruction, the
User shall notify the Control Center without delay.

Chapter 6

FREQUENCY AND VOLTAGE MANAGEMENT CODE

6.1 Introduction

This Chapter describes the method by which all Users of the CTS shall co-operate
with the Control Centre in contributing towards effective control of the system
frequency and managing the voltage of the CTS.

6.2 Objective

In order to maintain the security and integrity of the CTS, to avoid damage to the
CTS and to User Equipment, and to maintain Voltages at User Connection Points
within the limits specified in the Connection Code, it is necessary that the Control
Center operates the Transmission System, Dispatches and manages Voltages in
such a manner as to achieve operation within applicable Frequency and Voltage
limits at all times. The objective of this chapter is to define the actions required to
enable the Control Center to maintain Cambodia Transmission System frequency
and voltages within acceptable levels.

6.3 Methods of Frequency control

System Frequency is a continuously changing variable that is determined and
controlled by the balance between System Demand and total energy available. If
Demand is greater than generation, the Frequency falls while if generation is
greater than Demand, the Frequency rises. The immediate second-by-second
balancing (fine tuning) is provided by generating units through automatic control
systems (such as governor action) in conjunction with the Operating Margin. The
automatic control systems continuously modulate the outputs of the Generating
Unit to provide corrective damping to the many System Frequency variations.

Sometimes there may be a sudden and significant mismatch between Demand and
Generation which may be caused by tripping of transmission line or Generating
Unit or rapid change in Demand. A sudden reduction in generation will cause the
System Frequency to fall rapidly and sufficiently such that it crosses the pre-set
levels of the low-frequency relays. The  low-frequency relays operate to provide
coarse automatic energy balancing by  Demand reduction and/or increase in
generation. The governor action together  with the action of the low-frequency
relay will provide the corrective action to  restore the frequency to normal level.
When these actions are not sufficient Control Center shall issue instructions to
achieve manual Demand reduction and/or increase in generation. For rapid and
sufficient increase in System Frequency, the Control Center shall issue
instructions to reduce generation. The Control Center shall restore the Operating
Margins as soon as possible.

6.4  Requirements of Generating Unit Governor system

6.4.1  Other than as permitted in accordance with Section

6.4.2, Generation
Units when synchronized to the CTS shall operate at all times under the
control of a governor control system  (or frequency control device). No
time delays other than those necessarily inherent in the design of the
governor control system shall be introduced. The design, implementation
and operation of the governor control system shall be agreed with the NTL
prior to the commissioning of the Generating Unit.

6.4.2  The provisions of Section 6.4.1 may be contravened where:
a.  The action is essential for the safety of personnel and/or to avoid
damage to Equipment, in which case the Generation Licensee shall
inform the Control Center of the restriction without delay; or
b.  In order to (acting in accordance with Good Industry Practice)
secure the reliability of the Generation Unit; or
c.  The restriction is agreed by the Control Center in advance; or
d.  The restriction is in accordance with a Dispatch Instruction given
by the Control Center.

6.5 Load Reduction

In the event sufficient generation capacity is not available to match the load,
it will be necessary to reduce the load to maintain the balance. The load
reduction may be done automatically through operation of Under-frequency
relays or may be done manually on instruction from Control Center. The
automatic load reduction scheme may be implemented by the User with load
or can be provided by the transmission system owner on the main
Subtransmission feeders to reduce the load as a single block.

6.6 Methods of Voltage control

The strategies used for Voltage control include:
a.  Transformer tap-changing, reactor and capacitor switching, and
other control methods which involve utilization of Transmission
System Equipment only;
b.  Tap-changing on Generating Unit Transformers;
c.  Demand power factor correction;
d.  Utilization of Generating Unit Reactive Power capability, both by
means of AVR control and also  MVAr Dispatch Instructions
issued by the Control Center to Generation Licensees.

6.7 Requirements of Demand Power Factor correction and Capacitor Switching

6.7.1  Demand power factor correction

The reactive power compensation should be provided near the load so that
the load at the load bus is close to unity power factor and the reactive
capacity of Generating Units is available to meet the VAr requirements
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during a contingency. Hence where possible, the reactive power
compensation may be provided near the load.

6.7.2  Capacitor switching

Reactive compensation at the substations should be provided, as far as
possible, on the medium voltage system with a view to meeting the reactive
power requirements closer to the load and to avoid the need for VAr transfer
from high voltage system to the medium voltage system.

6.8 Requirements of Generation Unit AVR control

6.8.1  The excitation system of each Generation Unit shall normally be operated
under the control of a continuously acting AVR, which shall be set so as to
maintain a constant terminal voltage. The Generation Licensee may not
disable or restrict the operation of the AVR except in accordance with
Section 6.8.2, in which event the Generation Licensee  shall notify the
Control Center without delay.

6.8.2  The Generation Licensee may only disable or restrict AVR action where:
a.  The action is essential for the safety of personnel and/or
Equipment;
b.  In order to (acting in accordance with Prudent Utility Practice),
secure the reliability of the Generation Unit;
c.  The restriction is agreed between the Control Center and the
Generation Licensee in advance.

6.8.3  The Control Center shall, by means of Dispatch Instructions, instruct
Generation Licensees to adjust the Reactive Power output of Generating
Units.

6.8.4  Other facilities which shall be utilized by the Control Center, where
appropriate, in order to exercise Voltage Control shall include:
a.  Switching in or out of dedicated Voltage Control facilities, such as
capacitor banks and reactors;
b.  Tap-changing on 230/115 kV Transmission System transformers;
c.  Switching out of transmission lines in order to reduce the
capacitive contribution of the CTS.

Chapter 7

CONTINGENCY PLANNING CODE

7.1 Introduction

In the operation of a transmission system, there will be emergency situations
when security of the transmission system is subject to abnormal levels of risk.
Such emergency situations may arise due to natural disasters,  civil disturbance,
severe weather conditions, mal-operation of protection system or other unplanned
events and may cause disruption of electric supply.  Experience has shown that
electricity supply systems can suffer partial or total shutdown. For quick and safe
recovery of the supply system, comprehensive restoration plans should be in
place.

7.2 Objective

The objective of this Chapter is to ensure that in the event of a Partial Shutdown
or Total Shutdown of the CTS, normal supply is restored to all consumers as
quickly and as safely as practicable.

This objective can be subdivided:
a.  To outline the general restoration strategy which will be adopted
by the Control Center in the event of a Partial or Total Shutdown
of the CTS;
b.  To establish the responsibility of the Control Center to produce and
maintain a comprehensive Power System Restoration Plan,
covering both Partial and Total Shutdowns;
c.  To establish the responsibility of Users to co-operate with the
formation and execution of the Power System Restoration Plan,
d.  To ensure that the Control Center and User personnel who will
potentially be involved with the Power System Restoration Plan,
should be adequately trained and fully familiar with the relevant
details of the plan.

7.3 Generating Units with Black Start capability

The NTL shall establish the capacity and strategic location of the Generating
Units capable of providing Black Start services and shall ensure that such
Generating Units are installed and maintained to be used for restoration of the
System after a Total or Partial Shutdown.

The Control Center shall ensure that Generating Units providing Black Start
services are periodically tested to ensure that the generating units are in working
order, can be loaded to rated capacity  and will be able to provide the required
power to restore the System after a Total or Partial Shut Down

7.4 Restoration Strategy

The situation prevailing prior to the occurrence of the contingency, e.g.
availability of specific Generating Units, transmission circuits and load demands,
will largely determine the restorations process to be adopted in the event of a total
shutdown. Control Center shall advise all Users of the situation and follow the
strategy as outlined below for restoration.

User’s persons authorized for operation  and control of User System shall be
available at User’s end for communication and acceptance of all operational
communications throughout the contingency. Communication channels shall be
restricted to operational communications only till normalcy is restored.

The Control Center shall instruct all  relevant Generation Licensees having
Generating Plants with Black Start capability to commence their pre-planned
Black Start procedure. Supply shall be extended to Grid substations and
Generating Plants requiring start-up power. Control Center may require licensees
with Embedded Generating Units to extend start-up power supply to Generating
Plants as may be feasible.

The Control Center shall prepare the CTS for restoration by creating discrete
power islands with no interconnection. Close co-ordination with concerned Users
with load shall be maintained during the restoration process to arrange for discrete
demand blocks becoming available to stabilize Generating Units, as these become
available in individual islands. Generating Plants to whom start up power supply
is made available shall sequence their  start up to match their auxiliary power
demand with supply available.

Generation Licensees shall inform Control Center as Generating Units become
available to take load, in order that the Control Center may assess the MW
demand which the Generating Unit is likely to pick up on circuit breaker closure.

The control Center shall co-ordinate with Generation Licensees and Users with
load to:
a.  Form discrete power islands with one Generating Unit feeding
some local demand.
b.  Extend islands by adding more Generating Units and more demand
in a coordinated manner, maintaining load generation balance.
c.  Synchronize islands to form a larger, more stable island.

The Control Center shall, taking into  account sites where system synchronizers
are available, gradually extend the synchronization until all demand is restored.

The Control Center shall utilize any assistance available from External Inter-
connectors, if appropriate, at any time to assist in the above process.
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In case of a Partial Shutdown, the Control Center shall ensure with Users that
security of the healthy part of the CTS is maintained.

The Control Center shall gradually extend the healthy system to provide start-up
power to appropriate Generating Units.

The Control Center with close co-ordination with Users with load and Generation
Licensees shall gradually restore demand to match generation as it becomes
available.

All Users shall take care to ensure load generation balance is maintained at all
times under the direction of Control Center.

7.5  Restoration Plan

The Power System Restoration Plan for Total Shutdown and Partial Shutdown
will be developed and maintained by the Control Center in consultation with the
Users as appropriate. A set of basic restoration scenarios will be developed. The
procedure for Power System Restoration  shall be that notified by the Control
Center to the User at the time of a Partial or Total Shutdown. Each User shall
abide by the instructions of the Control  Center during the restoration process,
subject to safety of personnel and of the Equipment.

It shall be the responsibility of the User to ensure that any of its personnel who
may reasonably be expected to be involved in Power System Restoration are
familiar with, and are adequately trained and experienced in their standing
instructions and other obligations so as  to be able to implement the procedures
and comply with any procedures notified by the Control Center.

7.6 Responsibilities

The Control Center shall maintain a record of Generating Plant Black Start
capability and associated Black Start plans.

The Control Center shall be responsible  for directing the restoration process by
co-ordination with all Users.

Users with load shall be responsible  for sectionalizing the Subtransmission/
Distribution System into discrete, unconnected blocks of demand. They shall
advise the Control Center of the amount of MW likely to be picked up by the
synchronizing Generating Units.

Generation Licensees shall be responsible for commencing their planned Black
Start procedure on the instruction of Control Center and for steadily increasing
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their generation according to the demand  which the Control Center is able to
make available.

7.7 Special considerations

During the restoration process following Partial or Total Shutdown, normal
standards of voltage and frequency shall not apply.

All Users shall pay special attention in carrying out the procedures so that
secondary collapse due to undue haste or in-appropriate loading is avoided.

Despite the urgency of the situation, careful, prompt and complete logging of all
operations and operational messages shall  be ensured by all Users to facilitate
subsequent investigation into the incident and the efficiency of the restoration
process. Such investigation shall be conducted promptly after the incident.

Chapter 8

SAFETY COORDINATION CODE

8.1 Introduction

In order to adequately maintain and repair the Transmission System Equipment it
will be necessary for the Transmission System Owner and/or its agents to work on
or in close proximity to Transmission System Equipment, or in close proximity to
User’s Equipment.

For repair and maintenance of its equipments, Users and/or their agents will
similarly need to work on or in close  proximity to User’s Equipment which is
connected to, or capable of being connected to, in an approved manner, the
Transmission System, and from time to time to work in close proximity to
Transmission System Equipment.

It will also be necessary to facilitate work by third parties in close proximity to
Transmission System Equipment.

Safety coordination between Transmission System Owners, Users and third
parties will be required to perform the above stated works with full safety.

8.2 Objective

The objective of this Chapter is to ensure that the Transmission System Owner,
Users and their respective agents operate in accordance with approved safety
rules, which ensure the safety of personnel working on or in close proximity to
Transmission System Equipment or User’s Equipment at the Connection Site.

This will normally involve deenergizing electrical Equipment and suitably
isolating / disconnecting (from all sources of Energy) and Earthing that
Equipment such that it cannot be made live.

8.3  Control Persons

All Users shall nominate suitably authorized persons suitably  authorized to be
responsible for the co-ordination of safety at each Connection Site. These persons
shall be referred to as Control Persons. Normally the person in charge of
operations of equipments at the Connection Site during each shift of operation
may be nominated as Control Persons. Where operating persons are not working
in shifts, suitable responsible persons  (if required more than one) who are in
charge of operations of equipments at the Connection Site and available for
coordination may be nominated as Control Persons.  All Users shall issue a list of
Control Persons (names, designations and  telephone numbers) to all Users who
have a direct control boundary at the User’s Connection Point. This list shall be
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updated promptly whenever there is change of name, designation or telephone
number.

8.4  Procedure

Whenever work at a Connection Site is to be carried out, the Control Person, of
the User, wishing to carry out work shall directly contact the other relevant
Control Person. Code words (passwords to ensure that the interaction relating to
the operations is with an authorized person) will be agreed at the time of work to
ensure correct identification of both parties.

Contact between the Control Persons shall normally be by direct telephone.
Should the work extend over more than one shift, the Control Person shall ensure
that the relief Control Person is fully briefed on the nature of the work and on the
code words in operation.

The Control Persons shall co-operate to establish and maintain the precautions
necessary for the required work to be carried out in a safe manner. The
precautions to be taken may be according to a safety procedure in force or as
agreed between the parties and may include display of caution signs, use of
locking arrangements, providing connections to the earth system etc. Both the
established isolation and the established earth shall be locked in position, where
such facilities exist, and shall be clearly identified.

Work shall not commence until the Control Person, of the User, wishing to carry
out the work, is satisfied that all the safety precautions have been established.
This Control Person shall issue agreed safety documentation to the working party
to allow work to commence.

When work is completed and safety precautions are no longer required, the
Control Person who has been responsible  for the work being carried out shall
make direct contact with the other Control Person to request removal of those
safety precautions.

The equipment shall only be considered as suitable for return to service when all
safety precautions are confirmed as removed, by direct communication using code
word contact between the two Control Persons, and return of agreed safety
documentation from the working party has taken place.

Any dispute concerning Safety Coordination shall be resolved at an appropriate
higher level of authority of both parties.

8.5 Special Considerations

For work at Connection Site all Users shall comply with the agreed safety rules.
All equipment on Connection Site which may be used for the purpose of safety
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co-ordination and establishment of isolation and earthing, shall be permanently
and clearly marked with an identification number or name, that number or name
being unique on that Connection Site. This equipment shall be regularly inspected
and maintained in accordance with manufacturer’s specification.

Each Control Person shall maintain a legibly written safety log, in chronological
order, of all operations and messages relating to safety co-ordination sent and
received by him. All safety logs shall be retained for a period of not less than 2
years.

Chapter 9

CODE ON REPORTING OF EVENT AND ACCIDENT

9.1 Introduction

This Chapter sets out the requirements for the reporting of Events on the CTS or
User’s System which have had an Operational Effect,
a.  on the CTS – in the case of an Event occurring on the System of a
User or Users; and
b.  on the System of a User or Users – in the case of an Event
occurring on the CTS.

This Chapter also sets out the requirements for reporting Accidents on the CTS.

9.2 Objective

The objective of this Chapter is to provide for the exchange of information so that
the implications of an Event can be considered, possible risks arising from it can
be assessed and appropriate action taken by the relevant party in order to assist in
maintaining the integrity of the CTS.

9.3 Reportable Events

Typical examples of reportable incidents that could affect the Transmission
System are the following:
a.  Exceptionally high/low system voltage or frequency.
b.  Serious equipment problem, e.g. transmission circuit, transformer
or bus-bar.
c.  Tripping of Generating Unit.
d.  System split, Transmission System breakaway or Black Start.
e.  Major fire incidents.
f.  Failure of protection.
g.  Equipment and transmission line overload.
h.  Minor equipment alarms.

The last two reportable incidents are typical examples of those, which are of
lesser consequence, but which still affect the Transmission System and can be
reasonably classed as minor. They will require corrective  action but may not
warrant management reporting until a later, more reasonable time.

9.4 Reporting Procedure

9.4.1  All reportable events occurring in lines and equipment of 22 kV and above
at grid substations and Generating Plants shall promptly be reported orally
by the User whose equipment has experienced the incident (The Reporting
User) to any other significantly affected Users and to the Control Center.

9.4.2  If the reporting event cannot be classed as minor, then within 1 (one) hour
of being informed by the Reporting User, Control Center may ask for a
written report on any incident.

9.4.3  The Reporting User shall submit an initial written report within two hours
of asking for a written report by Control Center. This has to be further
followed up by the submission of a comprehensive report within 48 hours
of the submission of the initial written report.
In other cases the Reporting User shall submit a report within 5 (five)
working days to Control Center.

9.4.4  Control Center may call for a report from any User on any reportable
incident affecting other Users and  the Transmission System Owner; in
case the same is not reported by such User whose equipment might have
been source of the reportable incident.

9.4.5  The format of such a report will be as agreed at the Grid Code Review
Panel, but will typically contain the following information:
a.  Location of incident.
b.  Date and time of incident.
c.  Equipment involved.
d.  Supplies interrupted and duration, if applicable.
e.  Amount of generation lost, if applicable.
f.  Brief description of incident.
g.  Estimate of time to return to service.
h.  Name of originator.

9.5 Major Failure

Following a major failure, the NTL and other Users shall co-operate to inquire
and establish the cause of such failure and produce appropriate recommendations.
The NTL shall report the major failure to EAC immediately for information and
shall submit the enquiry report to EAC within 2(two) months of the incident.

9.6 Accident Reporting

In both fatal and non-fatal accidents, the User, whose equipment is involved in the
accident, shall furnish a report to EAC in the prescribed form. The report on fatal
accident shall be furnished to EAC within 3 working days and the report on non-
fatal accident shall be furnished to EAC within 10 working days.

Chapter 10

PROTECTION CODE

10.1  Introduction

The transmission system in Cambodia will consist of transmission systems owned
and operated by more than one transmission licensee. It is expected to be
connected with the transmission system of neighboring countries also. The
Generating Plants connected to the system are/ will be owned by more than one
licensee. In order to safeguard the transmission system as well as a Users system
from faults, which may occur on another User’s system, it is essential that certain
minimum standards of protection are adopted. The settings of the protection
system should remain properly coordinated at all times to ensure speedy isolation
of faulty equipment.

10.2  Objective

The objective of this Chapter is to define the minimum protection requirements
for any equipment connected to the CTS and thereby minimize disruptions due to
faults.

10.3  General Principles

No item of electrical equipment shall be allowed to remain connected to the CTS
unless it is covered by appropriate protection aimed at reliability, selectivity,
speed and sensitivity.

All Users shall co-operate with the NTL to ensure correct and appropriate settings
of protection to achieve effective, discriminatory removal of faulty equipment
within the maximum time for fault clearance specified in Section 10.5.

Protection settings shall not be altered, or protection bypassed and/or
disconnected without consultation and agreement of the NTL and all affected
Users. In the case where protection  is bypassed and / or disconnected, by
agreement, then the cause must be rectified and the protection restored to normal
condition as quickly as possible. If agreement has not been reached the electrical
equipment will be removed from service forthwith.

10.4  Protection Coordination

The NTL shall be responsible for arranging periodical meetings between all Users
to discuss coordination of protection including coordination of relay settings. The
NTL may arrange separate meetings for the Users of each separate system, if the
CTS consist of more than one separate system. The NTL shall investigate any
mal-function of protection or other unsatisfactory protection issues. Users shall
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take prompt action to correct any protection mal-function or  issue as discussed
and agreed to in these periodical meetings.

10.5 Maximum Time for Fault Clearance

From a stability consideration, the maximum time for clearance of faults (from
fault inception to circuit breaker arc extinction) by primary protection on any
User’s system directly connected to the CTS, or faults on the CTS itself, for
different system voltages shall be as follows:

a.  230 kV  100 milliseconds
b.  115 kV  140 milliseconds

Slower fault clearance times for faults on a User’s system may be agreed to, but
only if, in the opinion of the NTL, system conditions allow this.

The maximum time for clearance of faults by back up protection, on failure of the
primary protection, shall be 300 milliseconds.

10.6  Protection Requirements

10.6.1  Generating Plant

All Generating Units and all associated electrical equipment of the
Generating Plant connected to the CTS shall be protected by adequate
protection so that the CTS do not suffer due to any disturbance originating
from the Generating Unit.

Apart from other suitable protection,  the Generating Unit shall have loss of
excitation protection, over/under frequency protection.

10.6.2   Transmission Line

Every High Voltage line taking off from a Generating Plant or a substation
shall have protection consisting of at least a primary protection scheme and a
back up protection scheme. The recommended protection schemes for lines
of different voltages are stated below. The Transmission Line owner may
provide different protection scheme than stated below only in consultation
with and approval of the NTL.

230 kV lines – Primary Protection – Current differential protection relay in
conjunction with optical fiber communication from the transmission line.
Back up Protection –  Three or more  zone distance protection with phase
fault and earth fault measuring elements and with permissive inter trip for
accelerating tripping at remote end in case of zone-2 fault. Reclosing
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provision shall be high speed first shot for single phase and three phase re-
closing and further delayed multiple shot three phase re-closing.

115 kV lines – Three or more zone static distance protection with permissive
inter-trip for accelerating tripping at remote end in case of a zone-2 fault
shall be provided as primary protection. The backup protection will be
directional three poles over current and earth fault protection.

10.6.3  Subtransmission Line

All 22 kV lines at Connection Point shall be provided with a minimum of
over-current and earth fault protection. Parallel feeders or ring feeders shall
be provided with directional time lag  over-current and earth fault relays.
Other feeders may be provided with  non-directional time lag over-current
and earth fault relay with suitable settings to obtain discrimination between
adjacent relay stations. For long feeders, the relay should incorporate a high
set instantaneous element.

10.6.4  Transformers (230/115 kV, 230/22 kV and 115/22 kV)

All windings of HV/HV and HV/MV power transformers shall be protected
by differential relays and REF relays. In addition there shall be back up time
lag over current and earth fault protection. For transformers operating in
parallel, such back up protection shall have directional feature. For
protection against heavy short circuits, the over current relays should
incorporate a high set instantaneous element. In  addition to electrical
protection, gas operated relays, winding temperature protection and oil
temperature protection shall be provided.

10.6.5  Substation Bus-bar and Fire Protection

All Users shall provide adequate bus zone protection for substation busbars
in 230 kV substations.

Adequate precautions shall be taken and protection shall be provided against
fire hazards to all Equipment of the Users.

Chapter 11

METERING, COMMUNICATION AND DATA ACQUISITION CODE

11.1  Introduction

It is necessary that adequate communication facilities and procedures are
established between the Control Center and Users to allow the timely transfer of
information, in order that the Control  Center may fulfill its obligations with
regard to the operation of the CTS. In Cambodia, if there is more than one Control
Center, the communication has to be between the Users and respective Control
Center which controls the operation relating to the User.

11.2  Objective

The objective of this Section is to define the minimum acceptable metering,
communication and data acquisition requirements to enable the Control Center to
manage the CTS in a safe and economic manner.

11.3 Metering

The Meter and metering equipment shall confirm to the provisions of Technical
standards issued by MIME. The Commercial Metering shall be provided and
operated as per the provisions of the respective agreements. Suitable additional
metering shall be provided to measure operational data.

11.4  Contact Location

11.4.1  Control Center – The contact location for Control Center for
communication on matters pertaining to the real-time operation of the CTS
shall be the Control Center located at Phnom Penh or the Regional Control
Center of the region as notified to each User by the NTL. The NTL will,
from time to time, notify to Users the contact location for the relevant
Control Center and any changes to such contact locations, and the User
shall, as required, contact the relevant notified Control Center.

11.4.2  Generation Licensees – The Generating Plant contact location and
personnel shall be notified by the Generation Licensee to the relevant
Control Center prior to connection and thereafter updated as appropriate.
The Generation Licensee is required to provide a control facility staffed at
appropriate staffing levels at all times for each Generating Plant.

11.4.3  External Inter-connector – The External Inter-connector contact location,
which may be its control center, shall be notified by the external Inter-
connector to the Control Center.
11.4.4  Transmission Licensees with HV system – The NTL and Special Purpose
Transmission Licensees shall notify  their attended HV Substations as
contact location to the Control Center.

11.4.5  Users with load – The NTL and Special Purpose Transmission Licensees
with MV Subtransmission system  connected directly with CTS,
Distribution Licensees and Consumers connected directly with CTS are
required to provide the Control Center with the contact information of a
Responsible Operator(s) who shall  respond to communications from the
Control Center without undue delay.

11.5  Communication Facilities

The minimum communications facilities which are to be installed and maintained
between the Control Center and the User are described below:

11.5.1  Supervisory control and Data Acquisition (SCADA)

All equipments for SCADA provided  by the Users shall comply with
International Electrotechnical Commission (IEC) Standards for SCADA and
Communications Equipment and shall meet such standards notified by the
Control Center, acting reasonably,  in advance of their design and
procurement.

SCADA remote terminal unit (RTU) shall be required at the User Site for
the transmission of signals and indications to and from the Control Center.
Interface cabinets shall be installed in the User’s Equipment room if
required. The Transmission System owner shall provide the cables to
interconnect User’s interface cable with the Control Center. The provision
and maintenance of wiring and signaling from the User’s Equipment to the
User’s interface cable shall be the responsibility of the User.

The signals and indications which must be provided by Users for
transmission by SCADA equipment to the Control Center are the signals and
indications as the Control Center may from time to time by notice to Users
reasonably require. (The information  will be required from Generating
Plants, substations and HV consumers). The information from Generating
Plant may include switch gear positions, Unit voltage, MW-MVAr
generation, unit transformer tap position, Equipment voltage, MW-MVAr
generation, from substations may include switch gear positions, HV/LV
voltage, MW-MVAr flow in HV feeders and MV feeders, frequency etc)

11.5.2  Telephone and Facsimile

Each User (generating plant and substation and HV consumer) shall be
responsible for the provision and maintenance of no fewer than one

telephone and one facsimile unit on separate lines that shall be reserved for
operational purposes only, and shall be continuously attended to and
answered without undue delay.

11.5.3  Electronic Mail

The Users shall provide the Control  Center with the electronic mailing
address of the contact person as defined in this Chapter and vice versa. The
provider of this service shall be selected to meet the real-time operational
requirements of the Control Center.

Chapter 12

GLOSSARY AND DEFINITIONS

12.1  Definitions

In the Grid Code the following words and expressions shall, unless the subject
matter or context otherwise requires or is inconsistent therewith, bear the
following meanings:

Active Energy The electrical energy produced, flowing or supplied by an
electric circuit during a time interval, being the integral
with respect to time of the instantaneous active power,
measured in units of watt-hours (Wh) or standard multiples
thereof, i.e. :
1000 Wh  =  1 Kilo Watt-hour (kWh)
1000 kWh = 1 Mega Watt-hour (MWh)
1000 MWh = 1 Giga Watt-hour (GWh)
1000 GWh = 1 Tera Watt-hour (TWh)

Active Power The product of voltage and in-phase component of
alternating current measured in units of Watts or standard
multiples thereof.

Amended Connection Agreement
An agreement between a User and NTL (or User, NTL and
SPTL) which specifies the terms and conditions relating to
the renovation or modification of the User System or
Equipment at an existing connection point on the CTS

Ancillary Service Support services such as Frequency Regulating Reserve
and Contingency Reserve, Reactive Power support, and
Black start capability which  are necessary to support the
transmission capacity and Energy that are essential in
maintaining power quality and  the reliability and security
of the CTS

Automatic Voltage Regulator (AVR)
A continuously acting automatic excitation control system
so as to maintain a Generating Unit’s terminal at a desired
set-point

Black Start The procedure necessary for a recovery from a Total
Shutdown or Partial Shutdown
Cambodia Transmission System (CTS)
Each of the interconnected Transmission System owned or
operated by the National Transmission Licensee and/or
Special Purpose Transmission Licensees in Cambodia
taken individually and collectively.

Central Dispatch The process of scheduling and issuing Dispatch Instruction
in relation to Generating Units direct to a Generating Plant
by the Control Center pursuant to the Grid Code

Commercial Metering The metering, based on whose meter readings the bills are
raised for the service provided in accordance with the
respective agreements

Connection Agreement
An agreement between a User and NTL (or User, NTL and
SPTL) which specifies the terms and conditions relating to
the connection to and/or use of the CTS

Connection Point The physical point where the User’s Equipment or System
is connected with the CTS and includes the Connection
Point where the Transmission Systems of two or more
owners are joined

Connection Site The site owned (or  occupied) by a Transmission System
owner or a User in which there is a Connection Point.

Contingency Reserve The margin of available generation capacity over Demand
Forecast which is required to cover against uncertainties in
availability of generation  capacity and against Demand
Forecast errors or variations

Control Center A location used for the purpose of control and operation of
the Cambodia Transmission System or a part of it and the
connected User’s System

Control Person A person identified as having responsibility for
coordination of safety at Connection Site under Section 8.3

Degradation of the CTS
A condition resulting from a User Development or a CTS
expansion project that has a material effect on the CTS or
the System of other Users  and which can be verified
through technical studies
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Demand  The Active Power and/or reactive Power at a given instant
or averaged over a specified interval of time, that is
actually delivered or is expected to be delivered by an
electrical Equipment or supply System. It is expressed in
Watts (W) and/or VARs and standard multiples thereof.

Demand Forecast The projected Demand and Active energy related to a
Connection Point or CTS

Detailed Planning Data
As referred in Chapter 2: Planning Code

Dispatch  The issue of instruction  by Control Center to Generation
Licensees in respect of operation of Generating Units under
their control

Dispatch Instruction  An instruction given by the Control Center to the
Generation Licensee to change output or manner of
operation of the Generating Unit

Distribution Licensee The licensee who has been issued distribution license by
EAC

Distribution System The system consisting mainly of electric lines and
associated facilities operating at MV and LV owned by a
Distribution Licensee, extending between the delivery
points on the transmission, subtransmission system or
Generating Plant connection and the consumer’s
installation.

Earthing  The provision of an electrical connection between one or
more conductors and earth

Electricity Authority of Cambodia (EAC)
The regulator for electricity sector in Cambodia,
established under the Electricity Law

Electricité Du Cambodge (EDC)
The wholly state owned utility established by Royal Decree
No. ChS/RKT/0396/10 dated March 09, 1996.

Embedded Generating Plant
A Generating Plant that has no direct connection to the
CTS but that is connected to a Subtransmission System or

Distribution system connected to the CTS or the system of
any User

Energy  Unless otherwise qualified, refers to the Active Energy

Equipment All apparatus, machines, conductors, etc. used as part of, or
in connection with, an electrical installation

Event  An unscheduled or unplanned occurrence of an abrupt
change or disturbance in a  power System due to fault,
Equipment outage or adverse weather condition

External Interconnection
Equipment for the transmission of electricity to (from) the
CTS from (to) a transmission or distribution system located
outside the Kingdom of Cambodia

External Interconnector
The party which controls an External Interconnection

Frequency The number of alternating current cycles per second
(expressed in Hertz) at which a System is running

Frequency Regulating Reserve
Refers to a Generating Unit that assists in Frequency
control by providing automatic Primary and/or Secondary
Frequency Response

Generating Plant A facility, consisting  of one or more Generating Units,
where electric energy is produced from some other form of
energy by means of suitable apparatus

Generating Unit 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 Licensee  The licensee who has been issued generation license by
EAC

Generation Schedule Refers to the schedule that indicates the hourly output of
the Generating Units and the list of the Generating units
that will provide ancillary Services for the next scheduled
day or for the rest period of the day

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Grid   The High Voltage backbone System of interconnected
transmission lines, substations, and related facilities for the
conveyance of bulk power. Also known as Transmission
System

High Voltage (HV) A voltage level exceeding 35 kV

Hydro Generating Unit A Generating Unit having generation of electricity
through water power

IEC Standard Standard issued by International Electrotechnical
Commission

Load Shedding The reduction in System Demand brought about by the
controlled disconnection of consumers

Medium Voltage (MV)
A voltage level exceeding 600 Volts but not exceeding 35
kV

Merit Order  A list of Generating Units in ascending order of marginal
operating cost taking fuel constraints and other operating
constraints into consideration

Merit Order Table Refers to the list showing the marginal operating costs in
ascending order and the corresponding available capacities
of the Generating Units taking fuel constraints and other
operating constraints into consideration

Meter  A device for measuring and recording units of electrical
energy

Minimum Stable Loading
The minimum Demand that a Generating Unit can safely
maintain for an indefinite period of time

National Plan The overall plan for development of electricity sector in
Cambodia prepared by MIME

National Transmission Licensee (NTL)
EDC – the licensee who has been issued National
Transmission License by EAC

Operating Margin The margin of generation over the total Demand (including
losses) that is necessary for ensuring power quality and the
Security of the CTS. Operating Margin is the sum of the
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Frequency Regulating Reserve and the Contingency
Reserve.

Outage  The state of Equipment when it is fully or partly non-
operational to allow for construction, maintenance or due to
some event directly associated with the Equipment. An
Outage may or may not cause an interruption of supply of
electricity to consumers.

Outage Plan A plan showing the expected Outages.

Partial Shutdown The condition when a part of the CTS is isolated from the
rest of the CTS and in that part of the CTS, all generation
has shutdown and there is no electricity supply from
External Interconnection

Planned Outage An Outage included in the approved Outage Plan

Power System The CTS and all User Systems in Cambodia

Power System Restoration
The restoration of the Power System or part of the Power
System to a state of normal operation from a state of Total
Shutdown or Partial shutdown as the context requires

Power System Restoration Plan
A plan, prepared and maintained by the Control Center
pursuant to Chapter 7: Contingency Planning Code, setting
out guidelines assisting those involved in Power System
Restoration to achieve Power System Restoration as safely
and as quickly as possible.

Prudent Utility Practice
The standards, practices, methods and procedures,
confirming to safety and legal requirements, attained by
exercising that degree of skill, diligence, prudence and
foresight which would reasonably and ordinarily be
expected from skilled and experienced operatives engaged
in the same type of undertaking under the same or similar
circumstances

Reactive Power The product of voltage and quadrature component of the
current or the product of voltage and current and the sine of
the phase angle between them. It is measured in units of
volt-amperes reactive (VAr) and standard multiples thereof.

Reactive Power Capability Curve
A diagram which shows the Reactive power capability limit
versus the Active Power within which a Generating Unit is
expected to operate under normal conditions

Reliability It is the ability of a power System to continuously provide
service to its consumers

Scheduling The process of compiling and issuing a Generation
Schedule, as set out in Chapter 5: Scheduling and Dispatch
Code

Section  A Section or part of this Grid Code, which is identified as
covering a specific topic

Security The continuous operation of a power System in the normal
state, ensuring safe and adequate supply of power to
consumers, even when some components of the System are
on Outage

Site Responsibility Document
As referred in Section 3.6 of Chapter 3: Connection Code

Special Purpose Transmission Licensee (SPTL)
The licensee who has been issued Special Purpose
Transmission License by EAC

Standard Planning Data
As referred in Chapter 2: Planning Code

Subtransmission System
The System consisting of Medium Voltage electric lines
used in connection with transmission of electricity from a
substation or Power Station  to different  Distribution
Licensees and Medium Voltage consumers including the
Equipments and Meters owned or operated by the SPTL
and designated as Subtransmission lines in the license of
the SPTL.

System  Refers to a Transmission System or User System as the
case may be

System Security The continuous operation of a power system in the normal
state, ensuring safe and adequate supply of power to

consumers, even when some components of the system are
on outage

Technical Standard The standards for the electricity sector of Cambodia issued
by MIME

Total Shutdown The condition when all generation in the CTS has ceased
and there is no electricity supply from External
Interconnection

Grid Code The code covering all activities relating to the connections,
the operation and use of the Transmission System in
Cambodia including the operation of electric lines and plant
connected to the Transmission System in Cambodia

Grid Code Review Panel/ Panel
The Panel set up under Chapter 1: General Provisions of
the Grid Code

Transmission System The system consisting of High Voltage electric lines used
in connection with transmission of electricity from one
Power Station to a substation or to another Power Station or
between substations or to or from any External
Interconnection including any Equipments (including the
Medium Voltage bays in substations) and meters owned or
operated by the National Transmission Licensee or a
Special Purpose Transmission Licensee in connection with
the transmission of electricity. Transmission System in
relation to the National Transmission Licensee or a Special
Purpose Transmission Licensee means the system, owned
or operated by that licensee.

Transmission System Owner
The NTL or SPTL who owns the relevant Transmission
System

User  A person, including the NTL, SPTL, who uses the CTS and
who must comply with the provisions of the Grid Code

User Development The System or Equipment to be connected to the CTS or to
be modified

User System A system owned or operated by a User comprising:
a.  Generating Units; and/or
b.  Transmission System; and/or
c.  Subtransmission System; and/or
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d.  Distribution system; and/or
e.  Equipments of a consumer connected to the CTS

Voltage  The electromotive force  or electric potential difference
between two points, which causes the flow of electric
current in an electric circuit

Voltage Control The retention of the Voltage on the System within
acceptable limits

12.2  Abbreviations

A Ampere
AVR Automatic Voltage Regulator
CTS  Cambodia Transmission System
DC Direct Current
EAC  Electricity Authority of Cambodia
EDC  Electricité Du Cambodge
HV High Voltage
IEC  International Electrotechnical Commission
kV Kilo Volts
LV Low Voltage
MIME  Ministry of Industry Mines and Energy
MV Medium Voltage
MVA Megavolt-ampere
MVAr Megavolt-ampere reactive
MW Megawatt
NTL  National Transmission Licensee
REF  Restricted Earth Fault
RMS Root-mean-square
RTU  Remote terminal unit
SCADA Supervisory Control and Data Acquisition
SPTL  Special Purpose Transmission Licensee
TS Transmission System
VAr Volt-Ampere-Reactive

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