The Saudi Arabian Distribution Code...The Saudi Arabian Distribution Code Page 3 of 99 10 DCRP-2011-010 12-10-2011 Clause 1.3(g), the word “new” deleted from the definition of

The Saudi Arabian

Distribution Code

Issue: 03

Revision:02

October 2018

Prepared By:

Saudi Electricity Company (SEC)

No part of this publication may be reproduced, stored in a retrieval system or

transmitted in any form or by any means electronic, mechanical, photocopying,

recording or otherwise, without written permission of the Electricity & Cogeneration

Regulatory Authority.

The Saudi Arabian Distribution Code

Page 2 of

99

CHRONOLOGY OF SAUDI ARABIAN DISTRIBUTION CODE REVISIONS

Sr. No. Revision No. Date Detail of Revision

01 DCRP-2011-001 8-01-2011 The figure of Medium

Voltage Level, 69KV, given

under clauses DPC2.2,

DCC4.6 & 2.2 was

inconsistent with the figure of

36 KV given in the Clause

DCD52, i.e. definition of

“Medium Voltage”. Clause

DCD52 has been revised with

figure 69Kv.

02 DCRP-2011-002 8-01-2011 Corrections/modifications

made in Clause DCC6.3.1.

03 DCRP-2011-003 8-01-2011 Clause DOC3.1(a) has been

corrected by removing the

word “not” which was

depicting wrong sense of the

sentence.

04 DCRP-2011-004 8-01-2011 There was no part 7

“Reference” in the DC.

Therefore necessary

corrections have been made

under “Part-1” Introduction

& Contents.

05 DCRP-2011-005 8-01-2011 There was no Annexure 2 in

the DC. Therefore Clause

DGC 9.3 has been modified

by changing the words

“Application form can be

obtained through ECRA”.

06 DCRP-2011-006 8-01-2011 Clause DGC6.4 has been

modified by incorporating

the words “as per standard

amendment form which can

be obtained through ECRA”.

07 DCRP-2011-007 8-01-2011 New voltage slab 400/230V

has been added in Table

DPC2.1.



DPC2.3.



1,clause 2.2


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10 DCRP-2011-010 12-10-2011 Clause 1.3(g), the word

“new” deleted from the

definition of ECRA.

11

DCRP-2011-011

12-10-2011

Clause DCD 42 , The

Definition of “Generator”

was modified.

12 DCRP-2011-012 20-03-2012 Clause DPC 2.7 “Earthing

Requirement (Bundling of

LV neutral &MV Ground)

was modified

13 DCRP-2011-013 20-03-2012 Clause DPC 2.8.1, New KPI

“MAIFI” added in this clause

14 DCRP-2011-014 20-03-2012 Short circuit level for new

voltage slab 400/230V has

been added in Table DCC

4.1.

15 15 Nos. Corrections

Omissions, Typographical

mistakes, in two parts , (11+4)

, have been made along with

insertion of “List of

Abbreviations.” Which was

missing in the DC.

16 DCRP-2011-015 25-03-2012 In Clause DCC 4.1.2 , new

Standard SASO added in

addition to existing standard

IEC.

17 DCRP-2011-016 25-03-2012 New sub Clause DCC 4.1.2

(a) added under clause DCC

4.1.2.

18 DCRP-2011-017 25-03-2012 New sub Clause DCC 4.1.2

(b)) added under clause DCC

4.1.2.

19 DCRP-2011-018 25-03-2012 Existing Clause DCC 4.1.3

has been modified

20 DCRP-2011-019 2-04-2012 In compliance to decree # 324

dated 20-09-1430, a foot note

regarding new voltage slab

230/400 V was added under

Table DPC2.1

21 DCRP-2011-020 In compliance to decree #

2/27/23 dated 21-10-1433,

existing clause DPC2.4 ,

power factor modified to

enhance the power factor.


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TABLE OF CONTENTS

Sr. No Description Page No.

CHRONOLOGY OF SAUDI ARABIAN DISTRIBUTION CODE

REVISIONS

2

FOREWORD 7

PREFACE 8

LIST OF ABBREVIATIONS 9

PART-1 INTRODUCTION 10

1.1 Purpose of the Distribution Code 10

1.2 Structure of Distribution Code 12

1.3 Structure of Electricity Supply Industry 13

1.4 Use of the Distribution System 14

PART-2 GENERAL CONDITIONS 17

DGC1 Introduction 17

DGC2 Scope 17

DGC3 Implementation 17

DGC4 Unforeseen Circumstances 17

DGC5 Hierarchy 18

DGC6 Distribution Code Panel 18

DGC7 Communications between DSP(S) and Users 20

DGC8 Emergency Situations 20

DGC9 Derogations 20

DGC10 Confidentiality 23

DGC11 Force Majeure 24

DGC12 Disputes and Dispute Resolution Procedures 24

PART-3 PLANNING 25

DPC1 Introduction 25

DPC2 Design Standard 25

DPC2.1 Frequency 25

DPC2.2 Voltages 26

DPC2.3 Harmonics 28

DPC2.4 Power Factor 28

DPC2.5 Phase Unbalance 29

DPC2.6 Voltage Stability 29

DPC2.7 Earthing Requirement 30

DPC2.8 Security of Supply 31

DPC3 Transfer of Planning Data 33

DPC3.1 Planning Information to be Provided by the Users 33

DPC3.2 Information to be exchanged 34

DPC3.3 Planning Studies 35

PART-4 CONNECTION CONDITIONS 36

DCC1 Introduction 36

DCC2 Information Required for Connections 37

DCC3 Connection Arrangements 39

DCC3.1 Connection Voltage 39


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DCC3.2 Information Provided by DSP(s) 40

DCC3.3 Ownership Boundaries 40

DCC4 Technical Requirements for Connections 41

DCC4.1 Connection Standards 41

DCC4.2 Protection Requirements 42

DCC4.3 Earthing 44

DCC4.4 Voltage Regulation and Control 45

DCC4.5 Short-Circuit Levels 45

DCC4.6 Insulation Levels 45

DCC4.7 Capacitive and Inductive Effects 46

DCC4.8 Voltage Disturbances 47

DCC5 Metering and Telemetry 47

DCC6 Embedded Generator Requirements 48

DCC6.1 Introduction 48

DCC6.2 Specific Rules for Embedded Generators 48

DCC6.3 Provision of Information 49

DCC6.4 Information Provided by DSP(s) 52

DCC6.5 Technical Requirements 52

DCC6.6 Rate of Change of Frequency 54

DCC6.7 Islanding Disconnection 54

DCC6.8 Energization and Ramping of Generating Units 54

DCC6.9 Energization / ramping of Embedded Power Park Modules 55

DCC.6.10 Active Power Performance 55

DCC.6.11 Active Power Control 56

DCC.6.12 Reactive Power capacity and controllability 58

DCC.6.13 Communication 61

DCC.6.14 Fault Ride through 62

DCC.6.15 Short Circuit Contribution 63

DCC.6.16 Black Start Capability 64

DCC.6.17 Generating Plant Commissioning Tests 64

PART-5 OPEARTION 65

DOC1 Demand Forecasting 65

DOC1.1 Introduction 65

DOC1.2 Scope 65

DOC1.3 Capability of receiving Dispatch Instructions 66

DOC1.4 Information Flow and Co-Ordination 66

DOC1.5 Demand Forecast Data 66

DOC1.6 Information regarding Output and planned shutdowns 66

DOC2 Operational Planning 67


DOC2.2 Scope 67

DOC2.3 Provision of Information 68

DOC2.4 Time Scales and Data 68

DOC2.5 Information from Embedded Generators 68

DOC2.6 Information to Users 68

DOC3 Demand Control 69


DOC3.2 Scope 70


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DOC3.3 Methods of Demand Control 70

DOC3.4 Implementation of Demand Control 70

DOC4 Operational Communication and Liaison 71


DOC4.2 Scope 71

DOC4.3 Procedure 71

DOC4.4 Significant Incidents 72

DOC5 Event Reporting 72


DOC5.2 Scope 72

DOC5.3 Procedure 73

DOC5.4 Joint Investigations 73

DOC5.5 Matters to be included in a Written Report of a Significant

Incident

73

DOC6 System Tests 74


DOC6.2 Scope 74

DOC6.3 Procedure 75

DOC7 Monitoring, Testing and Investigation 77


DOC7.2 Scope 77

DOC7.3 Procedure 77

DOC8 Safety Co-Ordination 78


DOC8.2 Objectives 78

DOC8.3 Scope 78

DOC8.4 Procedure 78

DOC8.5 Safety at the DSP(S)/User Interface 79

DOC8.6 Safety Rules 80

PART-6 Glossary 81

ANNEXURE

SECURITY AND PLANNING

STANDARDS FOR THE DISTRIBUTION

SYSTEM (Demand Customers Only)


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FORWARD

This is the second issue of the Saudi Arabian Distribution Code. Such work has been

accomplished by extensive efforts from Saudi Electricity Company (“SEC”) and was

subjected to thorough technical and legal reviews by internationally renowned consultants

including ESBI of Ireland and CMS Cameron McKenna of UK as well as a number of major

Saudi stakeholders and the Electricity & Co-Generation Regulatory Authority

(“ECRA”).

The Distribution Code is designed to indicate the procedures for both planning and

operational purposes and covers both normal and exceptional circumstances. It is

however a live working document. It will be, from time to time, subject to change and/or

revision to reflect stages of development of the regulatory framework of the industry and

changes to comply with legislation and good industry practice. The proposals for

change will be received by the Distribution Code Review Panel (“DCRP”). The rules and

responsibilities of the DCRP are described in chapter DGC6. Upon receipt of such

proposals for change, the DCRP will carry out the necessary process as appropriate to

study these proposals and officially prepare a report of recommendations to ECRA for

its approval. The DCRP is a stakeholders representation panel and its members are

outlined in chapter DGC6.3 of the Distribution Code.

As a User of this Distribution Code, it is your responsibility to ensure that you possess the

most up to date issue. Issues of the Distribution Code can be downloaded from ECRA’s

web site www.ecra.gov.sa.

This Preface is provided to Users and to prospective Users for their information only and

does not constitute a part of the Distribution Code.

http://www.ecra.gov.sa/


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PREFACE

The Saudi Arabian Distribution Code has been developed to define the

rules and regulations for all parties for accessing and using the

Distribution System. The objective is to establish the obligations of the

distribution service providers (DSP's) and other system Users TSP, (Transmission

Service Provider), Embedded Generators, other distribution service providers and

Customers for accessing and using the Distribution System, more specifically to:

(i) define obligations, responsibilities, and accountabilities of

all the parties for ensuring open, transparent, non-

discriminatory, and economic access and use of the system

while maintaining its safe, reliable and efficient operation;

(ii) define minimum technical requirements; and

(iii) Set out the information exchange obligations.


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LIST OF ABBREVIATIONS

A Ampere

ASAI Average System Availability Index

AVR Automatic Voltage Regulator

BIL Basic Insulation Level

CAIDI Customer Average Interruption Duration Index

CHP Combined Heat and Power

CMS Content Management System (Cameron McKenna UK -Law Firm)

DCRP Distribution Code Review Panel

DSP Distribution Service Provider

ECRA Electricity and Co-generation Regulatory Authority

ESBI Electricity Supply Board Ireland

HV High Voltage

HZ Hertz

IEC International Electro-Technical Commission

IEEE Institute of Electrical and Electronics Engineers

IR Index of Reliability

KA Kilo Ampere

KPI Key Performance Indicator

KV Kilo volt

KVA Kilo volt ampere

KW Kilo watt

KWh Kilo watt hour

Kvarh Kilo var hour

LV Low Voltage

MVA mega volt ampere

MV Medium Voltage

Mvar mega var

Mvarh mega var hour

MW mega watt

MWh megawatt hour

RMS root mean square

RMU Ring Main Unit

SAIDI System Average Interruption Duration Index

SAIFI System Average Interruption Frequency Index

SAGC Saudi Arabian Grid Code

SASO The Saudi Standards, Metrology and Quality Organization

SCADA Supervisory Control and Data Acquisition

THVD Total Harmonic Voltage Distortion

TSP Transmission Service Provider

V Volt

VA volt ampere

Var volt ampere reactive

W watt

Wh watt hour

X/R reactance over resistance


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PART 1: INTRODUCTION

Contents

1.1 Purpose of the Distribution Code

1.2 Structure of the Distribution Code

1.3 Structure of the Electricity Supply Industry

1.4 Use of the Distribution System

1.1 Purpose of the Distribution Code

The Distribution Code specifies the technical aspects of the working relationship

between the DSP(s) and all Users of the Distribution system which are necessary to

ensure a stable, reliable and economical electrical Distribution system and to enable

the DSP(s) to fulfill their obligations specified in the Saudi Arabian Grid Code

(SAGC).

The relationship between all Users, the Grid Code and the Distribution Code is shown

diagrammatically in Figure 1.1.


Page 11 of 99


Page 12 of 99

1.2 Structure of Distribution Code

The Distribution Code is in seven parts, as follows:

Part 1: Introduction

This outlines the purpose of the Code, its relationship with the Saudi Arabian Grid Code (SAGC), the structure of the electricity supply industry, and how the various parts of the Code are relevant to the different Users of the Distribution system.

Part 2: General Conditions

This presents provisions which are of general application to all parts of the Code.

Part 3: Planning

This specifies the technical and design criteria and the procedures to be employed in the

planning and development of the Distribution system.

Part 4: Connection Conditions

These define the minimum standards for methods of connection to the Distribution

System.

Part 5: Operation

This part addresses various operational issues including load forecasting, planning

outages, reporting of operational changes and events, safety matters and procedures for

dealing with emergencies.

Part 6: Definitions

Annexure

SECURITY AND PLANNINGSTANDARDS FOR

THE DISTRIBUTION SYSTEM (Demand Customers Only)

.


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1.3 Structure of the Electricity Supply Industry

The Electricity Supply Industry comprises the following entities:

(a) The Transmission Service Provider (TSP) owns and operates the

Transmission System. The Transmission System transports the electricity,

generated by Generating Units, to the Distribution System, through which

most Customers will be supplied. Some Generating Plant is connected

directly to the Distribution System and is referred to as Embedded

Generation.

(b) The Distribution Service Provider (DSP(s)) is responsible for operating

and maintaining secure, reliable and efficient electricity Distribution

System. The Distribution System transports electricity from the

Transmission System or from Embedded Generating Units to the final

Customer.

(c) Retailers supply electricity to Customers. For this purpose, Retailers will

be entitled to use both the Transmission System and the Distribution

System for the transport of electricity from Generating Units to

Customers.

(d) Traders supply electricity to other licensees and/ or eligible Customers.

For this purpose, Traders will be entitled to use both the Transmission

System and the Distribution System for the transport of electricity

from Generating Units to those licensees or eligible Customers

(e) Generators generate electricity which is fed onto the Transmission or

Distribution Systems. Generating Units are classified according to their

voltage, output power and whether or not they are subject to Central

Dispatch by the TSP.

(f) Customers may purchase electricity from the DSP(s), Traders or

Retailers. Some Customers have their own generating Plant for supplying

all or part of their own needs.

(g) ECRA was established to regulate the Electricity Industry.


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1.4 Use of the Distribution System

Use of the Distribution System may involve any of the following transactions:

(a) Any connection at entry to or exit from the Distribution System, which is

called an interface point. An entry point is the connection between the

Distribution System and the Transmission System or an Isolated/

Embedded Generating Plant. An exit point is the connection between the

Distribution System and the Customer’s premises.

(b) Use of the Distribution System to transport electricity between

entry and exit points.

(c) Construction of a Connection Point.

(d) Work and/or operation associated with equipment at the interface with

the Distribution System.

Users connected to the Distribution System shall comply with the

relevant sections of the Distribution Code. The categories of Users of

the Distribution System are described in Table 1 and the sections of the

Code that apply to each User are shown in Table 2. Users shall also

comply with the requirements of relevant legislation, which from time

to time comes into force.

Customers and Embedded Generators shall be required to have Connection

Agreements with the DSP(s) and Retailers/ Traders shall be required to enter into

Use of System Agreements with the DSP(s) or the TSP as the case may be.

There are a number of technical documents annexed to the Distribution Code.

Users are bound to comply with the requirements of these documents as

appropriate to their circumstances. Users shall also be required to enter into

technical and other agreements. Customers and Generator / Embedded

Generators shall be required to have Connection Agreements with the DSP(s)

and Retailers/ Traders shall be required to enter into Use of System Agreements

with the DSP(s) or the TSP as the case may be.


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Table 1

CATEGORIES OF USERS OF THE DISTRIBUTION SYSTEM

A1 Embedded Generator with a Registered Capacity ≥ 10 MW

A2 Embedded Generator with a Registered Capacity ≥ 2 MW <10 MW

A3 Embedded Generator with a Registered Capacity ≥200kW < 2 MW

A4 Embedded Generator with a Registered Capacity <200kW

B1 Major Customers connected at High Voltage

B2 Customers connected at Medium Voltage

B3 Industrial and commercial Customers connected at Low Voltage

B4 Domestic Customers

C Retailers/ Traders

D The Distribution Service Provider (DSP(s))


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SECTIONS OF THE DISTRIBUTION CODE APPLYING TO PARTICULAR

CATEGORIES OF USERS OF THE DISTRIBUTION SYSTEM

CATEGORY OF USERS

Dist. Code Ref. A1 A2 A3 A4 A5 B1 B2 B3 B4 C D

DGC D D D D D D D D D D D

DPC1 R R R R R R R R R R R

DPC2 D D D D R R R R R R D

DPC3 R R R R R R R R R R R

DCC1 R R R R R R R R R R R



DCC4 D D D D NA D D D D R D

DCC5 D D D D NA D D R R R D

DCC6 D D D D NA D D D D R D

DOC1 NA D NA NA NA D D NA NA NA D

DOC2 D D D D NA D NA NA NA NA D

DOC5 R R D R R R R R R NA D

DOC7 D D D R NA D NA NA NA NA D

DOC8 D D D R NA D NA NA NA NA D

Table 2 NA : Not Applicable

D : Applicable with specific obligations R : Relevant for information but no specific obligations

Note(1): Customers with all sizes of Embedded Generation (A1 to A4 in Table 2)

must, in addition to compliance with the requirements placed on their specific

category as Generators also comply with the requirements of the relevant

customer category (B1 to B4).]. Note (2): Any User proposing to close, retire, withdraw from service, or otherwise

cease to maintain and keep available for Dispatch in accordance with Good

Industry Practice any Generating Station or Generating Units with Registered

Capacity (3) greater than two (2) MW in aggregate shall give the DSP at least

twenty-four (24) calendar months’ notice of such action. The DSP will notify

the TSP according to agreed timescales in cases where the Registered Capacity

of the retiring Generating Unit (or in aggregate Generating Units) is 10MW or

more.


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PART 2: GENERAL CONDITIONS Contents

DGC1 Introduction

DGC2 Scope

DGC3 Implementation

DGC4 Unforeseen Circumstances

DGC5 Hierarchy

DGC6 Distribution Code Review Panel

DGC7 Communications between DSP(s) and Users

DGC8 Emergency Situations

DGC9 Derogations

DGC10 Confidentiality

DGC11 Force Majeure

DGC12 Disputes and Dispute Resolution Procedures

DGC1: Introduction

While each part of the Distribution Code presents the rules and provisions relating specifically to that part, the Distribution General Conditions (DGC) presents

provisions which are of general application to all parts of the Distribution Code.

DGC2: Scope

The General Conditions apply to all Users of the Distribution System.

DGC3: Implementation

DGC3.1 The Distribution Service Provider Licence imposes a duty upon

DSP(s) to implement and enforce the Distribution Code. In order to

do this DSP(s) may need access across boundaries, services, and

facilities from Users or to issue instructions to Users, for example to

isolate or disconnect Plant or apparatus. It is considered that these

cases will be exceptional and it is not, therefore, possible to

envisage precisely or comprehensively what DSP(s) might

reasonably require in order to carry out its duty.

DGC3.2 All Users are required to abide by the Distribution Code and also to provide the DSP(s) rights of access, services and facilities and to

comply with such instructions as may be reasonably required to

implement and enforce the Distribution Code.

DGC4: Unforeseen Circumstances


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DGC4.1 If circumstances arise which the provisions of the Distribution Code

have not foreseen, DSP(s) shall, to the extent reasonably

practicable in the circumstances, consult promptly and in good faith

with affected Users in an effort to reach agreement as to what

should be done. If agreement cannot be reached in the time

available DSP(s) shall determine what is to be done.

DGC4.2 Whenever DSP(s) makes a determination, it shall have regard,

wherever possible to the views expressed by Users, and in any

event, to what is reasonable in all the circumstances.

DGC4.3 Each User shall comply with all instructions given to it by DSP(s) following such a determination, provided that the instructions are consistent with the then current technical parameters of the

particular User’s System registered under the Distribution Code.

The DSP(s) shall promptly refer all such unforeseen circumstances

and any such determination to the Distribution Code Review Panel (DCRP) in accordance with DGC6.2.

DGC5: Hierarchy

DGC5.1 In the event of any conflict between the provisions of any direction of ECRA on the one hand and the provisions of the Distribution Code on the other, the provisions of ECRA‟s direction shall prevail.

DGC5.2 In the event of any conflict between the provisions of the Distribution

Code and any contract, agreement or arrangement between DSP(s) and a User, the provisions of the Distribution Code shall prevail

unless the Distribution Code expressly provides otherwise.

DGC5.3 In the event of any conflict between the provisions of the Distribution Code and the Transmission Code relating to system operation, the

provisions of the Transmission Code shall prevail [unless the Distribution Code expressly provides otherwise.]

DGC6: Distribution Code Review Panel

DGC6.1 The DSP(s) shall establish and maintain the DCRP, which shall be a

standing body, to carry out the functions referred to in DGC6.2.

DGC6.2 The Panel shall:

(a) keep the Distribution Code and its working under review,

(b) review all suggestions for amendments to the Distribution Code which


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ECRA or any User may submit to a DSP for consideration by the Panel

from time to time,

(c) recommend to ECRA amendments to the Distribution Code that the Panel feels are necessary or desirable and the reasons for the recommendation,

(d) issue guidance in relation to the Distribution Code and its implementation, performance and interpretation when asked to do so by

any User,

(e) consider what changes are necessary to the Distribution Code arising out of any unforeseen circumstances referred to it by DSP(s) under

DGC4,

(f) consider the effect of proposed changes on the Transmission Code,

(g) publish recommendations as to amendments to the Distribution Code that a DSP or the DCRP feels are necessary or desirable and the reasons for

the recommendations, and

(h) Produce an annual report of the activities of the DCRP.

DGC6.3 The Panel shall consist of:

(a) chairperson and two persons appointed by, and representing DSP(s), (b) one person appointed by and representing ECRA,

(c) one person representing the TSP,

(d) one person representing Generators with Embedded generation,

(e) one person representing Major Customers,

(f) one person representing suppliers, and

(g) one representative of the SASO

(h) one representative from KA-CARE

If any of the above parties fails to appoint its representative, (ECRA)

shall appoint one on its behalf.

Each of the above shall be appointed pursuant to the rules issued under clause

DGC6.4.

DGC6.4 The Panel shall establish and comply at all times with its own rules

and procedures relating to the conduct of its business, such rules and procedures to be known as the Constitution and Rules of the Panel, which

shall be approved by ECRA.

The DSP shall consult all Users liable to be affected in relation to all

proposed amendments to the Distribution Code as per standard amendment form (which can be obtained through ECRA) and shall submit

all proposed amendments to the Distribution Code to the DCRP for

discussion prior to such consultation. Unless an amendment is urgently


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required, ECRA will not amend the Distribution Code until all affected

Users have been given a reasonable opportunity to make representations

to ECRA concerning the amendment, and those representations have been taken into account.

ECRA will notify all DSP's and all affected Users of any amendment that ECRA makes to the Distribution Code.

DGC6.6 DCRP shall, from time to time or at the behest of ECRA having regard to the recommendations of the Panel, submit a revised Distribution Code

to ECRA for approval.

DGC7: Communications between DSP(s) and Users

DGC7.1 Unless otherwise specified in the Distribution Code the methods of operational communication and data transfer shall be agreed between

DSP(s) and Users from time to time.

DGC8: Emergency Situations

DGC8.1 Users should note that the provisions of the Distribution Code may be suspended, in whole or in part, pursuant to any directions given and/or

orders made by ECRA in emergency situations, pursuant to provisions of the Electricity Law issued by Royal Decree No. M/56.

DGC9: Derogations

DGC9.1 If a User finds that he is, or will be, unable to comply with any provision of the Distribution Code, then he will, without delay report such non-

compliance to DCRP and will, subject to the provisions of DGC9.2 make

such reasonable efforts as are required to remedy such non-compliance

as soon as reasonably practicable.

DGC9.2 Where the non-compliance is

(a) with reference to Plant and/or apparatus connected to the Distribution System and is caused solely or mainly as a result of a revision to the

Distribution Code,

or

(b) with reference to Plant and/or apparatus which is connected, approved to connect, or for which approval to connect to the Distribution System 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 DCRP a request for a derogation from such provision in

accordance with the requirements of DGC9.3 and shall provide DSP(s) with a copy


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of such application.

DGC9.3 A request for derogation from any provision of the Distribution Code shall contain the following:

(a) the issue number and the date of the Distribution Code provision against which the non-compliance or predicted noncompliance was identified;

(b) identification of the Plant and/or apparatus 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 non-compliance is possible) subject to DGC9.2 (b)

A standard Distribution Code Derogation Application form can be obtained through ECRA.

DGC9.4 If DSP(s) finds that they are, or will be, unable to comply with any provision of the Distribution Code, then they shall, subject to the

remaining provisions of DGC9 make such reasonable efforts as are

required to remedy such non-compliance as soon as reasonably

practicable.

DGC9.5 In the case where DSP(s) requests derogation, DSP(s) shall submit the information set out in DGC9.3 to DCRP.

DGC9.6 On receipt of any request for derogation, DCRP shall promptly consider such request and discuss the potential outcomes of such request with

ECRA. Following such discussion, DCRP shall recommend to ECRA such derogation, provided that DCRP considers that the grounds for the

derogation are reasonable.

DCRP will not recommend to ECRA such derogation if

(a) It would, or it is likely that it would, have a material adverse impact on

the security and stability of the Distribution System, or

(b) It would result in ECRA imposing unreasonable costs on the operation

of the Distribution System or Transmission System or on other Users.


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In its consideration of a derogation request by a User, DCRP may contact the relevant User and/or DSP(s) to obtain clarification of the request or to discuss

changes to the request.

Derogation from any provision of the Distribution Code shall contain the

following:

(a) the issue number and the date of the Distribution Code provision against which the derogation applies;

(b) identification of the provision with which the derogation applies;

(c) identification of the Plant and/or apparatus in respect of which a derogation

applies, and, if relevant, the nature and extent to which the derogation applies

including alternate compliance provision;

(d) the reason for the non-compliance requiring derogation; and

(e) the date by which the derogation ends if compliance will be achieved, or by which such derogation expires.

DGC9.7 To the extent of any derogation granted in accordance with this

DGC9, DSP(s) and/or the User (as the case may be) shall be relieved from its

obligation to comply with the applicable provision of the Distribution Code

and shall not be liable for failure to so comply but shall comply with any

alternate provision as set forth in the derogation. Should a derogation not be

granted, then the User will be required to comply with the applicable provision

of the Distribution Code and will be liable for failure to so comply.

DGC9.8 DCRP shall

(a) keep a register of all derogations which have been granted, identifying

the name of the person in respect of whom the derogation has been

granted, the relevant provision of the Distribution Code and the period

of the derogation, and

(b) on request from any User, provide a copy of such register of

derogations to such User.

DGC9.9 Where a material change in circumstance has occurred, a review of any

existing derogations, and any derogations under consideration, may be

initiated by DCRP at the request of ECRA, DSP(s), or Users.


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DGC10: Confidentiality

DGC10.1 The Distribution Code contains procedures under which the DSP(s) will receive

information from Users relating to the intentions of such Users. The DSP shall

not, except in pursuance of specific requirements of the Distribution Code,

disclose such information to any User or other person without the prior written

consent of the provider of the information, subject to the requirements of the

Distribution License.


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DGC11: Force Majeure

DGC11.1 If a DSP or User would breach the terms of the Distribution Code due to an

event outside the reasonable control of the DSP or User (a “Force Majeure

Event”), then those obligations under the Distribution Code that are

affected by the Force Majeure Event are suspended as long as the Force

Majeure Event continues.

DGC11.2 The DSP or the User must give the other party prompt notice of the Force

Majeure Event including full details, an estimate of likely duration, the

obligations affected by it and the steps taken to remove overcome or mitigate its effects.

DGC12: Disputes and Dispute Resolution Procedure

DGC12.1 any dispute that arises from time to time regarding how the Distribution

Code is being administered and interpreted shall be resolved following the

Dispute Resolution Procedure as set out in DGC12.2.

DGC12.2 The Distribution Code Dispute Resolution Process shall be in accordance with complaints handling procedure submitted by DSP under Implementing Regulations (Article 29).


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PART 3: PLANNING

Contents

DPC 1 Introduction

DPC2 Design Standards

DPC3 Transfer of Planning Data

DPC1: Introduction

DPC1.1 Part 3: Planning specifies the technical and design criteria and the procedures

to be complied with by DSP(s) in the planning and development of the

Distribution System. It also applies to Users in the planning and development

of their installations in so far as they affect the Distribution System.

DPC1.2 The Users‟ requirements may necessitate the reinforcement of, or an extension

to, the Distribution System and for reinforcement of, or extension to, the

relevant Transmission/Distribution interface capacity, such work being

identified by DSP(s) or TSP as appropriate.

DPC1.3 The time required for the planning and development of the Distribution

System and any consequential requirement of the interface with the

Transmission System, will depend on the type and extent of the necessary

reinforcement and/or extension work, the time required for obtaining planning

permission and right of way including any associated hearings, and the degree

of complexity in undertaking the new work while maintaining satisfactory

security and quality of supply.

DPC1.4 Reference is made in Part 3 to DSP(s) supplying information or advice to

Users. For avoidance of doubt, unless the context otherwise requires, such

information or advice shall be provided by DSP(s) as soon as practical

following a request by the User (whether during the application for connection

process or otherwise).

DPC2: Design Standards

DPC2.1 Frequency

The Frequency of supply is outside the control of DSP(s) however the standard

Frequency range is as follows:

The Transmission System Frequency is nominally 60Hz and shall normally be controlled within the limits of 59.9Hz to 60.1Hz.


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The system Frequency could rise to 62.5 Hz or fall to 57.0 Hz in exceptional

circumstances. Design of Generator’s Plant and apparatus must enable

operation of that Plant and apparatus within that range in accordance with the

following:

Below nominal

Frequency (Hz)

Above nominal

Frequency (Hz)

Operation

Requirement

58.8 - 60.0 60.0- 60.5 continuous

57.5 - 58.7 60.6 - 61.5 For period of 30

minutes

57.0 - 57.4 61.6 - 62.5 For period of 30

seconds

Users should ensure their equipment is designed or protected for these

exceptional circumstances.

DPC2.2 Voltages

The voltages listed in Table DPC2.1 shall be used as standard service voltages

at the interfaces with power Customers. The service voltage shall be

maintained within the range defined by the indicated lowest and highest

values, under steady state and normal system conditions and over the full

loading range of the system.

Where two voltages are listed e.g. 220/127V the lower value refers to the phase to neutral voltages. All other values are phase-to-phase voltages. Existing, but non-standard, voltages are listed in Table DPC2.2.


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Nominal Voltage

Lowest Voltage

Highest Voltage

220/127V 209/120V 231/134V

380/220V 360/209V 400/231V

400/230V 380/218.5V 420/241.5V

13.8KV 13.1KV 14.5KV

33KV 31.4KV 34.7KV

69KV 65.5KV 72.5KV

Table DPC2.1 : Standard Service Voltages

Note: * 220/127 V system will be obsolete within 25 years.

**The change of the old system 127/220 V with the new system

230/400 V in ongoing projects and facilities will be completed within 25

years as per the Council of Minister No. 324 dated 20/9/1430AH.

The service voltage shall be maintained [under steady state conditions] within

the range defined by the indicated lowest and highest values, under steady state

and normal system conditions and over the full loading range of the system.

Nominal Voltage

Lowest Voltage

Highest Voltage

11KV 10.45KV 11.55KV

34.5KV 32.78KV 36.23KV

Table DPC 2.2 : Existing, But Non-Standard, Voltages


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DPC2.3 Harmonics

The level of Harmonics in the power system shall comply with the limits set

out in Table DPC2.3, on a continuous basis.

Table DPC2.3: Maximum Continuous Harmonic Levels

Note:

N is the harmonic order, or multiple of the fundamental Frequency. Voltage distortion is

expressed as a percentage of the fundamental voltage.

The indicated values refer to maximum continuous levels.

DPC2.4 Power Factor

a) Each Customer with demand shall maintain a Power Factor of not less

than 0.85 lagging at the interface with DSP(s). No Customer shall present

a leading Power Factor to the DSP(s) system unless resulting from

operation of its Embedded Generation as agreed or instructed by the DSP.

By [date] Customers must improve their Demand related Power Factor to

not less than 0.90 lagging and by [date] to a minimum of 0.95 lagging.

The DSP may require proof that this has been achieved. This

improvement in lagging Power Factor is to enable the DSP(s) to comply

with obligations set down in the SAGC. Customers with both Embedded

generation and Demand shall not exceed any Power Factor or Reactive

Power limits set down in their Connection Agreement or notified to them

by the DSP further to the performance conditions of this Distribution

Nominal Voltage Total Harmonics Voltage

Distortion%

Individual Harmonics Voltage Distortion

Odd Even

230-400V 5.0 4.0 for N<14 2.0

1.5 for N>14

127-380 5.0 4.0 for N<14 2.0

1.5 for N>14

13.8KV 4.0 3.0 1.75

33KV 3.0 2.0 1.0


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Code.

b) Any Customer , classified as Industrial, Government and Commercial,

connected to the Distribution Network , having contracted load more than

1.0 MVA should exercise all precautionary measures to maintain 0.85

power factor. For such customers, the minimum allowable Power Factor

will be 0.9 after five years (from the date of 21-10-1433), and 0.95 after

ten years from the said date. In case of any deviation from this criteria an

additional tariff will be applied for reactive power consumption upon

such customer as per terms and conditions given in the decree # 2/27/23

dated 21-10-1433..

DPC2.5 Phase Unbalance

Under normal system conditions the three phase voltages shall be balanced at

MV, and higher voltages in the system, such that the negative phase sequence

voltage does not exceed 2% of the positive phase sequence voltage.

Customers with a dedicated transformer or those supplied at 13.8kV or a

higher voltage shall balance their loads, such that the load phase unbalance at

the Customer interface meets the above criterion. All other Customers shall

balance their loads over the three phases to the greatest degree possible. The

DSP(s) shall then balance these loads, within the power system, to meet the

above criterion.

DPC2.6 Voltage Stability

Voltage Dips

For non-repetitive voltage variation, or voltage dips, such as those associated

with motor-starting, welding equipment or power system switching, the

voltage variation shall not exceed 7% of the fundamental nominal voltage

under normal circumstances. Such variations shall not occur more frequently

than 3 times per day.

Application

No Customer shall connect equipment to the power system, which causes

voltage fluctuation at the Customer interface in excess of these requirements. The DSP(s) shall ensure that the power supply, at each Customer’s interface,

conforms to these requirements.


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DPC2.7 Earthing Requirements

1. Bonding of LV Neutral and MV Grounds.

LV neutral ground and any grounds associated with MV equipment / system

(e.g. MV metal work, cable screen, etc.) shall always be kept bonded.

2. Recommended ground resistance limits for different installations should be

as under:

System Ground 5 ohms

All Distribution Sub-

station 5 ohms

Surge Arresters 5 ohms

LV Distribution

Panel 10 ohms

3. LV metering Installations

It shall be essential for the Customer to provide grounding at his interface.

The Customer shall bring the ground wire to the grounding terminals

provided in the meter box. The ground wire of the Customer shall be

connected to the ground terminal inside the meter box. The ground terminal

shall be short linked with the neutral.

For more than one KWH -meters at one location, four KWH-meters shall be

connected to one ground rod. In case of additional KWH-meters at the

premises, additional ground rods shall be provided.

4. Ground mounted MV equipment

The equipment covered are RMU, MV switches etc, when separated from Transformer and Bulk Customer Indoor Switchgear. All metal work shall be bonded together and to the substation metalwork grounding system. Each continuous piece of metal that could form part of the path of a ground fault current shall be bonded to its neighbors so that continuity of grounding circuit does not depend on mechanical connections between components.

Licensed Distributors shall advise on the method of Earthing of the

Distribution System, for example, whether it is connected solidly to Earth or

through impedance. The specification of associated apparatus and Plant of the

Distribution System User shall meet the voltages that will be imposed on the


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apparatus and Plant as a result of the method of Earthing.

Notwithstanding the above, the DSP(s) shall provide a complete separate Earthing

code to define the Earthing requirements for safe use of the system. This code shall

constitute an integral part of the Distribution code.

Distribution System Users shall take precautions to limit the occurrence and effects of circulating currents in respect of the neutral points connected with Earth where there is more than one source of electricity.

DPC2.8 Security of Supply

DPC2.8.1 The Security Standard for the Distribution System is as follows:

Security of supply (also known as continuity) is evaluated in terms of five

indices, as follows:

(1) System Average Interruption Frequency Index (SAIFI)

SAIFI = Total Customer Interruptions

Total Connected Customers

- Measured in interruptions per 100 connected Customer

Years

(2) System Average Interruption Duration Index (SAIDI)

SAIDI =Total Customer Hours of Interruptions

Total Connected Customers

- Measured in Customer hours of interruptions per

connected Customer year

(3) Customer Average Interruption Duration Index (CAIDI)

CAIDI = SAIDI

SAIFI

- Measured in hours of interruption

(4) Index of Reliability (IR)”Average system availability Index” (ASAI)

IR (ASAI)= 8760 Hours/Year - SAIDI x 100 8760 Hours/Year


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(Expressed as a percentage)

(5) Momentary Average Interruption Frequency Index (MAIFI)

MAIFI = Total number of customer interruptions less than five minutes

Total number of customers served

The DSP(s) will have to comply with the security of supply standards limits as published by ECRA from time to time.

DPC2.8.2 DSP(s) shall use reasonable endeavors to maintain a supply from the

system. This cannot be ensured, since faults, planned maintenance and new

works outages and other circumstances outside DSP(s) control can cause

interruptions. On such occasions, DSP(s) shall use reasonable endeavors to

restore the supply or connection as soon as practicable but shall be under no

liability for any direct or indirect damage or associated loss incurred by the

User.

DPC2.8.3 Restoration times for different outage types are as follows:

Fault Outages: DSP(s) shall endeavor to restore access to the system as soon as

practically possible taking into consideration the KPI set values

approved by ECRA

Planned Outages: DSP(s) shall give five days’ notice to relevant Users of planned

supply interruptions. In some situations , to facilitate emergency

repairs or local outages affecting a small number of Customers,

shorter notice may be given.

Supply Curtailments: In some circumstances, it may be necessary to request Customers

to reduce load or to use standby supplies where appropriate. In these

situations DSP(s) shall endeavor to maintain access to the System.

In extreme cases where this may not be possible DSP(s) shall

endeavor to provide two days‟ notice to the Users.

Load Shedding: In extreme situations there may be generation shortages and load

shedding may be required. In these circumstances DSP(s) shall

notify Customers if possible but as this is an emergency situation it

may not be possible to do so. DSP(s) shall prepare a Load Shedding

Criterion and submit it to ECRA for approval. This criterion shall

detail the methodology for selection of load(s) to be shed.

DPC2.8.4 DSP(s) may disconnect Users under certain circumstances. These


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circumstances shall include:

(a) Where the Customer’s installation or use of electricity is such as to interfere

with the satisfactory operation of the Distribution or Transmission system or

to cause disturbance to other Customers.

(b) Where DSP(s) considers that the Customer’s installation is in a dangerous

condition.

(c) Where alterations, repairs, renewal or maintenance of the Distribution System

or DSP(s) assets or means of connection require the de-energisation of the

Connection Point.

(d) Where a Customer extends supply for use by another party whom DSP(s)

considers to be a separate Customer.

(e) In any other circumstances in which discretion is necessary or appropriate to

enable DSP(s) to comply with the Distribution Code and/or to operate the

Distribution System in accordance with Good Industry Practice or is required

by any law, direction, rule or regulation having the force of law.

DPC3: Transfer of Planning Data

DPC3.1 Planning information to be provided by Users.

DPC3.1.1 Users of the Distribution System shall provide sufficient planning data/

information as can reasonably be expected to be made available, when

requested by DSP(s) from time to time to enable DSP(s) to comply with the

requirements under its Distribution License.

DPC3.1.2 Users of the Distribution System shall provide planning data for specific

future time periods updated annually as necessary and including projected

Demand requirements, anticipated changes in maximum Demand, or

generating capacity, as appropriate. The data and timescales over which the

data is required are given in Distribution Operating Code 1 (DOC1).

DPC3.1.3 In addition to periodic updates of planning information, a User shall give

adequate notice of any significant change to their system or operating regime

to enable DSP(s) to prepare its development plans and implement any

necessary system modifications. In the event of unplanned changes in a User’s

System or operating regime a User shall notify DSP(s) as soon as is

practically possible to ensure any necessary measures can be implemented.

DPC3.1.4 Users shall also provide details of reactive compensation Plant directly or

indirectly connected to the Distribution System other than at Low Voltage,

including its rating and operational control.


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DPC3.1.5 Users may be required to provide DSP(s) with detailed data relating to the

interface between their System and that of the Distribution System covering

circuit parameters, switchgear and Protection arrangements of equipment

directly connected to or affecting the Distribution System to enable DSP(s) to

assess any implications associated with these points of connection.

DPC3.2 Information to be exchanged.

DPC3.2.1 On the request of a User, DSP(s) shall provide such information as may be

reasonably required on the design and other characteristics of the

Distribution System.

DPC3.2.2 Where DSP(s) proposes to make certain modifications to its system or

where it has received information from a User under DPC3.1 above, which

may impact on other User installations then DSP(s) will notify Users of the

proposal, subject to any constraint of confidentiality or timing.

DPC3.2.3 DSP(s) shall provide information on request to Users regarding the local

network conditions to enable them to determine their Protection

requirements.

DPC3.2.4 Where the User’s installation is connected to the bus bars of the Distribution

System, sufficient details may need to be exchanged with respect to User/

DSP(s) Ownership Boundary to enable an assessment to be made of transient

over voltage effects. The request for information may be initiated by either

DSP(s) or the User.

DPC3.2.5 Information may be exchanged between DSP(s) and the User on fault in feed levels at the feeding bus bar or point of connection to the Distribution System as appropriate, in the form of

- Three phase and single phase to earth short circuit in feed.

- The X/R ratio under three phase fault conditions.

DPC3.2.6 Information shall be exchanged between DSP(s) and User on Demand

Transfer Capability where the same Demand can be supplied from alternate

User points of supply. This shall include the proportion of Demand normally

fed from each point of supply and the arrangements (manual or automatic) for

transfer under planned/fault outage conditions.


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DPC3.3 Planning Studies

DPC3.3.1 In order to facilitate connections to the Distribution System DSP(s) shall prepare on request a study showing the implications of a connection at a particular point on the system.

DPC3.3.2 Under the terms of the Distribution Licence a reasonable charge (as submitted by DSP(s) and approved by ECRA) may be levied by DSP(s) for the planning study.

DPC3.3.3 A User or potential Users shall provide DSP(s) with information regarding the proposed facility including load details, interface arrangements, proposed Connection Point and import/export requirements.

DPC3.3.4 The studies shall normally be prepared within 28 days after the date of receipt

of the information or the agreement of the person making the request to pay

the cost of the study, whichever is the longer. In the case of Generators and

Major Customers seeking connection, depending on the nature and

complexity of the request, this period may extend up to 100 days or a further

28 days from the receipt of planning information from the TSP whichever is

the greater.

DPC3.3.5 Details of the procedures for application for connection to the Distribution

System are contained in [CUSTOMER SERIVICE MANUAL] as prepared

by DSP(s) and approved by ECRA.

DPC3.3.6 Where such information is available DSP(s) shall provide on request a

statement of present and future circuit capacities, forecast power flows and

loadings on part or parts of the Distribution System specified in the request

and shall include Fault Levels at each Distribution node covered by the request.

DSP(s) may levy a charge for the provision of this statement as approved by

ECRA on account of the reasonable costs incurred by DSP(s) in preparing

this statement. The statement shall be prepared within 28 days after the date of

receipt of the information or the agreement of the person making the request

to pay the cost of the statement, whichever is the longer. In the case of

Generators and Major Customers seeking connection this period may extend

up to 100 days depending on the nature and complexity of the request.

DPC3.3.7 The dates given in this DPC3.3 are target dates only and do not constitute a

legal commitment. DSP(s) shall however use reasonable endeavors to abide

by them.


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PART 4: CONNECTION CONDITIONS

Contents

DCC 1 Introduction

DCC2 Information Required for Connection

DCC3 Connection Arrangements

DCC4 Technical Requirements for Connections

DCC5 Metering and Telemetry

DCC6 Generator Requirements

DCC1: Introduction

DCC1.1 It is necessary to require certain minimum technical, design and operational

criteria to be met by User’s Plant and apparatus in order to maintain, insofar as

is permitted by Good Industry Practice, stable and secure operation of the

Distribution System for the benefit of all Users and for the Protection of the

Distribution System and User’s. Plant and apparatus directly connected to the


DCC1.2 The Connection Conditions define the minimum standards for the method of

connection to the Distribution System and the technical, design and

operational standards to which Users connecting to the Distribution System

shall comply.

DCC1.3 The Connection Conditions specify the technical arrangements required at the

Ownership Boundary between the Distribution System and the installation of

the User and are applicable to all voltage levels covered by the Distribution

Code.

DCC1.4 The Connection Conditions specify the information to be provided by Users

to ensure that adequate provision can be made by DSP(s) for new connections

or increases in existing load. It also applies to Generators who operate in

parallel with the Distribution System, where a connection is required.

Prospective Users shall provide to DSP(s) in good time all the details set out

in this section.

DCC1.5 In conjunction with the Connection Conditions, there are Connection

Agreements, which are bilateral agreements between DSP(s) and each User,

and which contain the detail specific to each User’s connection to and use of

the Distribution System. The Connection Agreement requires the User and

DSP(s) to comply with the terms of the Distribution Code.


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DCC2: Information Required for Connection

DCC2.1 For connections at Low Voltage it is possible in most cases to assess whether

a proposed connection is acceptable, and to determine the necessary supply

arrangements, from analysis of the following data:

(a) maximum kVA requirements.

(b) if applicable, type and electrical loading of equipment to be connected,

such as number and size of motors, cookers, showers, air conditioning,

space and water electrical heating loads and nature of Disturbing

Loads e.g. welding equipment.

(c) if applicable, type and electrical rating of Embedded generating

equipment to be connected, such as number, size of PV inverter, CHP

generator;

(d) if applicable, the expected performance of Embedded generating

equipment to be connected during and immediately after faults on the

relevant part of the LV System;

(e) if applicable, typical daily and seasonal load and generation patterns;

(f) single-line diagram of the installation

(g) the date when connection is required; and

(d) a plan showing the are covered by the installation and the location.

If a preliminary examination of this data indicates that more detailed information is reasonably required then it shall be provided to DSP(s) upon request.

DCC2.2 Information Requirements and timeframes for quotation and connection are

provided in [Customer service manual] as prepared by DSP(s) and approved

by ECRA. Copies of this manual are available on request from DSP(s).

DCC2.3 For connections at distribution level the provisions of DCC2.1 also apply.

Additionally, the following information is required, unless provision of part or

all the data is excused by the DSP:

(a) All Types of Demand

(i) Maximum Active Power requirements.

(ii) Maximum and Minimum Reactive Power requirements.


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(iii) Type of load and control arrangements (e.g. type of motor

start, controlled rectifier or large motor drives).

(iv) Maximum loading on each phase.

(v) Maximum harmonic currents that may be imposed on the


(vi) Details of cyclic load variations or fluctuating loads (as

below).

(b) All types of generation

(i) The type of Embedded Generation proposed (e.g.

Asynchronous generator - solar PV and inverter type /size and

overload capacity, wind powered – DFIG, FSIG or fully

converted and any special arrangements for network support;

Synchronous generator – fuel type).

(ii) The maximum (and, if appropriate minimum stable) MW

Output of the Generating Unit.

(iii) The kVAr or MVAr capability of the Generating Unit.

(iv) Where the Generating Unit is composed of separate units, a

diagram showing how these are arranged and protected.

(v) Information regarding the control arrangements:

arrangements for Frequency control / response;

arrangements for Voltage / Reactive Power / Power Factor

control.

(vi) If appropriate, the starting current and Power Factor during

starting and after faults.

(vii) Maximum phase-imbalance and harmonic currents which may

be imposed on the Distribution System during starting and

normal operation.

(b) Disturbing Loads

Comprehensive schedule of installed new equipment including details

of Disturbing Loads. These are loads which have the potential to

introduce Harmonics, Flicker or unbalance to the system. This could

adversely affect the supply quality to other Customers. Disturbing

loads could be non-linear loads, power converters/regulators and loads

with a widely fluctuating Demand. The type of load information

required for motive power loads, welding equipment, harmonic

producing/ non-linear loads and generating equipment can be obtained

from DSP(s) on request.

In the case of compensating equipment associated with Disturbing Loads, details and mode of operation to be provided so as to ensure

compliance with emission limits specified in DCC4.8.3.

(c) Fluctuating Loads


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Duty cycle, including details of cyclic or other variation of Active

Power and Reactive Power, in particular:

(i) the rates of change of Active Power and Reactive Power, both

increasing and decreasing;

(ii) the shortest repetitive time interval between fluctuations in

Active Power and Reactive Power; and

(iii) the magnitude of the largest step changes in Active Power and

Reactive Power, both increasing and decreasing.

DCC2.4 In some cases, more detailed information may be required to permit a full

assessment of the effect of the User’s load on the Distribution System. Such

information may include an indication of the pattern of buildup of load and a

proposed Commissioning programme. This information shall be specifically

requested by DSP(s) when necessary and shall be provided by the User within

a reasonable time.

DCC2.5 Users shall contact DSP(s) in advance if it is proposed to make any

significant change to the connection, electric lines or electric equipment,

install or operate any generating equipment or do anything else that could

affect the Distribution System or require alterations to connection.

DCC2.6 Users shall provide to DSP(s) any information reasonably required by

DSP(s) about the nature, or use by the User, of electrical equipment on the

User’s premises.

DCC3: Connection Arrangements

DCC3.1 Connection Voltage

DCC3.1.1 During the application for connection process DSP(s) shall, in consultation

with the User, specify the voltage level to which a User will be connected in

accordance with normal practice for the type of load to be supplied and

network characteristics.

DCC3.1.2 Generally, the voltage level will be the minimum nominal voltage in

standard use on the System, assessed against

(a) satisfactory operation of the installation,

(b) isolation of disturbance from other Customers,


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(c) lifecycle costs, and

(d) cost of connection

DCC3.1.3 DSP(s) may, on occasion, specify higher connection voltage in order to avoid

potential disturbances caused by the User’s apparatus to other Users of the

Distribution System or for other technical reasons or may agree alternative

methods for minimizing the effects of Disturbing Loads.

DCC3.2 Information Provided by DSP(s)

Based on the information provided by the User for a connection to the Distribution System, DSP(s) shall prepare a statement containing as many of

the following elements as are necessary for, or relevant to, the proposed

installation:

a) nominal voltage at which connection will be made;

(b) method of connection, extension and/or reinforcement details;

(c) the normal impedance to source at the point of connection;

(d) method of Earthing;

(e) maximum IMPORTED CAPACITY;

(f) individual Customer limits relating to

(i) Harmonic Distortion

(ii) Flicker

(iii) Phase Unbalance

(g) expected lead time of providing connection (following formal

acceptance of terms for supply); and

(h) Cost of connection.

DCC3.3 Ownership Boundaries

DCC3.3.1 The point or points at which supply is given or taken between the Distribution

System and Use r’s installation shall be agreed between DSP(s) and the User as

stipulated in the Connection Agreement between DSP(s) and the User.

DCC3.3.2 For LV supplies DSP(s) responsibility extends up to the Customer’s Connection

Point, which is normally at DSP(s) main Circuit Breaker as further specified in

the Connection Agreement between DSP(s) and the User.

DCC3.3.3 For Medium Voltage supplies the ownership boundaries shall be subject to


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specific agreement between the parties in each case. Changes in the

boundary arrangements proposed by either party shall be agreed in advance.

DCC3.3.4 All equipment at the Ownership Boundary shall meet the design

principles contained in DPC2 and DCC3. Connections for entry to and exit from the Distribution System shall incorporate a means of disconnection of the User’s installation by DSP(s).

DCC4: Technical Requirements for Connections

DCC4.1 Connection Standards

DCC4.1.1 A connection to the Distribution System may be by means of an overhead line, an

underground cable or a combination of both as detailed in the Connection

Agreement between DSP(s) and the User. The network configuration at the

Connection Point may take a number of forms suitable to the nature of the load

and network arrangements.

DCC4.1.2 From the time this code issued all equipment in an installation connected to

the Distribution System shall be designed, manufactured, tested and installed

in accordance with all applicable statutory obligations and shall conform to

relevant SASO standards or equivalent IEC standards with the latest version

at the time of the connection of the installation to the Distribution System.

a) For other equipment required to be connected to the Distribution System in an

existing or previous installation, installed before issuing this code, that are

comply with other different standards such as ANSI, ASTM, IEEE, UL, EN,

DIN, BS, … etc , those relevant standards can be applied for further period, in

condition that they shall have at least an equivalent degree of conformity

specified in SASO or equivalent IEC standards, and shall satisfy the service

conditions of Kingdom of Saudi Arabia. However the acceptability of any

alternative standards or codes is at the discretion of the DSP(s).

b) In case of any conflict between SASO standards and the other standards (or

codes), SASO or equivalent IEC standards shall be applied.

DCC4.1.3 If there is no relevant SASO standards or equivalent IEC standards available,

and/ or if DSP(s) considers it necessary, DSP(s) may notify Users that

supplemental specifications and/or standards shall be complied with, in which

case User Plant and apparatus shall so comply.

DCC4.1.4 All equipment in an installation connected to the Distribution System shall be

suitable for use at the operating Frequency of the Distribution System and at


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the voltage and short-circuit rating of the Distribution System as shown in

Tables DPC2.1 and DCC4.1 at the Connection Point. DSP(s) may require

certification that the equipment has been designed and installed in a

satisfactory manner. DSP(s) may also seek evidence that the equipment has

been tested for conformity with the standards.

DCC4.1.5 For Users connected at Low Voltage, installations shall comply with the

standards as in DCC4.1.2 and DCC4.1.3. Users complying with these rules and

regulations shall be deemed to comply with the requirements of the

Distribution Code as regards design and safety. DSP(s) may seek evidence

that the equipment has been tested for compliance with standards.

DCC4.1.6 Before connecting any User to the Distribution System it will be necessary for

DSP(s) to be reasonably satisfied that the User’s System complies with the appropriate requirements of the Distribution Code. An itemized statement of

compliance will be requested from each User prior to connection.

For all Embedded Generating Units, an equipment certificate and detailed data prepared by the equipment supplier or validated by a competent person shall be

additionally provided for compliance verification.

For Embedded Generating Units with a Registered Capacity of 2MW or greater,

the DSP has the right to carry out, or to witness certain testing to ensure

compliance verification. The DSP will indicate, in a timely manner, any tests so required, or tests to be witnessed by the DSP’s staff or appointed experts.

For Power Park Modules, it may not be possible initially to test certain requirements of the facility e.g. LVRT. Where the Power Park Module is

otherwise compliant, it shall receive an Temporary Connection Certificate. The

facility shall be equipped with an Event Recorder to a specification set down by the DSP and the performance shall be assessed for a period of nine months, after

which time, unless the Power Park Module fails to achieve the performance

standard set down in this Code, a Final Connection Certificate will be issued.

DCC4.2 Protection and Control Requirements

DCC4.2.1 Users shall ensure that faults in the User’s Plant and apparatus do not

unreasonably cause disturbances to the Distribution System or to other Users.

Without limiting this obligation, a User shall, prior to connection of the User’s

installation to the Distribution System, install the Protection equipment

specified in DCC4.2.4.

DCC4.2.2 Unless provided against, faults on the Distribution System can cause damage

to User’s Plant and apparatus through, for example, loss of a phase, over

voltage, or under voltage. The User shall take account of the established

practices of the particular network to which a connection is to be made, and


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ensure that Protection installed is compatible with that used by DSP(s). The

adequacy of the Protection installed by the User is the User’s responsibility.

DCC4.2.3 The User’s Protection arrangements at the Ownership Boundary, including

types of Equipment and Protection settings, shall be compatible with existing

system conditions and the Distribution System Protection practice as specified

by DSP(s) at the time of application. In particular

(a) the maximum clearance times (from fault current inception to arc

extinction) shall be within the limits established by DSP(s) in

accordance with Protection and equipment short circuit rating policy

adopted for the Distribution System;

(b) in connecting to the Distribution System the User should be aware that

fast and slow-speed automatic re-closing is a feature of Power System

operation. This is characterized by sudden de/re-energization of the

power supply. Dead times are typically 0.3s, 1s and 10s at Medium

Voltage and 3s and 60s on 38kV systems; and

(c) Users should also be aware that disconnection of one or two phases

only of a three phase system may be effected by Distribution

Protection arrangements for certain types of faults.

DCC4.2.4 The minimum Protection required for a User installation connected to the

Distribution System will vary according to type, size, and method of

connection (loop/tail/tee) and Earthing of the User System. It is anticipated

that a new connection may require all or some of the following Protection

facilities:

(a) three phase over current;

(b) earth fault Protection (suited to the local supply system);

(c) distance;

(d) inter-tripping; and

(e) Others.

DCC4.2.5 Where interface Circuit Breakers are used they shall be fitted with relays of a

type acceptable to DSP(s). These relays shall have three phases over current

elements and one earth fault element and shall have time-current

characteristics complying with standard types A, S and C of IEC 244.


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Maximum permissible relay settings at the ownership boundary, necessary to

provide selectivity any time in the future will be provided by DSP(s).

Distribution Protection aims to minimize the impact of faults including voltage

dip duration and must not be adversely affected by Customer’s Protection

limitations.

(a) In order to ensure satisfactory operation of the Distribution System,

Protection systems, operating times, discrimination, and sensitivity at

the ownership boundary shall be agreed between DSP(s) and the User

during the application for connection process, and may be reviewed

from time to time by DSP(s).

(b) In order to provide against the failure of a Circuit Breaker, or

equipment having a similar function, to operate correctly by

interrupting fault current on the system, back-up Protection shall

normally be provided by operation of other Circuit Breakers or

equipment having a similar function.

(c) Unless DSP(s) advises otherwise, the use of Protection and associated

equipment to limit the fault current in feed from the User’s system to

the Distribution System is not acceptable if the failure of that Protection

and associated equipment to operate as intended in the event of a fault

could cause equipment owned by DSP(s) to operate outside its short-

circuit rating.

DCC4.2.6 Protection relays shall be commissioned on site by the User who shall ensure

that the settings are below the maximum permitted levels. In certain cases

DSP(s) may wish to witness these tests and it shall be the responsibility of the

User to ensure that sufficient notice is given to DSP(s) in such cases. Users

shall ensure that the Protection settings remain below the maximum permitted

levels. This may require regular testing of the relays.

DCC4.3 Earthing

DCC4.3.1 Earthing of the part of the User’s installation that is connected to the

Distribution System shall comply with the requirements of DPC2.7.

DCC4.3.2 The arrangements for connecting the User’s installation with earth shall be

designed to comply with relevant international and national standards.

DCC4.3.3 The method of Earthing the Distribution System whether, for example, it is

connected to earth solidly or through impedance, shall be advised by DSP(s).

The specification of associated equipment shall be appropriate to the voltages

that will be imposed on the equipment as a result of the method of Earthing.


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DCC4.3.4 Where there is more than one source of energy, Users shall take precautions to

limit the occurrence and effects of circulating currents in respect of neutral

points connected with earth.

DCC4.4 Voltage Regulation and Control

DCC4.4.1 Extensions or connections to the Distribution System shall be designed so that

they do not hinder the necessary control of voltage on the Distribution System.

Information on the voltage regulation and control arrangements shall be made

available by DSP(s) if requested by the User.

DCC4.5 Short-Circuit Levels

DCC4.5.1 The short circuit rating of User’s equipment at the Connection Point shall not

be less than the design Fault Level of the Distribution System as shown in

Table-DCC4.1 below. DSP(s) shall take into account the contribution to Fault

Level of the User’s connected system and apparatus in the design of its system.

Table DCC4.1: Short Circuit Ratings

DCC4.6 Insulation Levels

DCC4.6.1 The basic insulation level (BIL) and power Frequency withstand voltage

for medium system voltages are as tabulated below:

Connection Voltage

Size of Load (KVA)

Short Circuit Level RMS Symmetrical (KA)

220/127V ≤152 21

>152 45

380/220V ≤500 20

>500 30

400/230V ≤500 20

>500 30

13.8KV All 21

33KV All

25

69KV All

31.5


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Note: The dry/wet power frequency withstand voltages are: Dry for one (1) minute

and wet for (10) seconds.

The basic insulation level (BIL) and power Frequency withstand voltage for low

system voltages are as tabulated below:

DCC4.7 Capacitive and Inductive Effects

DCC4.7.1 The User shall, when applying to make a connection, provide DSP(s) with

information as detailed in DPC3. Details shall be required of any capacitor

banks and reactors connected at Medium Voltage, which could affect the

Distribution System and which it is proposed to connect if agreed with DSP(s).

When requested by DSP(s), details shall also be provided of distributed circuit

capacitance and inductance. Sufficient detail is required for the following:

System Nominal Voltage

(KV RMS)

Altitude Above Mean Sea Level

up to 1000 meters above 1000 meters

69

BIL (KV peak) 325 350

Power Frequency Withstand Voltage (KV RMS)

140 160

33/34.5



70 80/75

11/13.8



38 50/45

System Nominal

Voltage (V)

BIL (KV Peak) Power Frequency Withstand

Voltage (KV RMS)

277/480

6

Equipment Panel wiring

230/400

3 2 220/380

127/220


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(a) to verify that controlling equipment of the Distribution System is

suitably rated;

(b) to show that the performance of the Distribution System will not be

impaired.

DCC4.8 Voltage Disturbances

DCC4.8.1 Users of the Distribution System must not generate voltage disturbances at a

level that would affect other Users. Users should in their own interest select

equipment that is capable of functioning satisfactorily in the presence of

disturbances at the levels that can be expected on the Distribution System as

stated in the DPC

DCC4.8.2 It is a condition of connection that equipment connected directly or indirectly

to the Distribution System shall conform to the requirements of the

Distribution Code as amended from time to time.

DCC4.8.3 Loads and installations shall comply with the emission limits, which are set

out in DPC2.3 (Harmonics), DPC2.4 (Power Factor), DPC2.5 (Phase

Unbalance) and DPC2.6 (Voltage Stability).

Special conditions for Generators are presented in DCC6.

DCC5: Metering and Telemetry

DCC5.1 The User may be required to provide such voltage, current, Frequency, Active

Power and Reactive Power pulses as are considered necessary by DSP(s) to

ensure adequate system monitoring. Details will be specified in the User’s

Connection Agreement.

DCC5.2 Centrally dispatched Generating Units, shall provide signals to the TSP as

required by the Saudi Arabian Grid Code (SAGC).

DCC5.3 If it is agreed between the parties that DSP(s) shall control the switchgear on

the User’s system, DSP(s) shall install the necessary telecontrol outstation.

Notwithstanding the above, it shall be the responsibility of the User to provide

the necessary control interface for the switchgear of the User which is to be

controlled.

DCC5.4 Metering principles applying to certain Users connected to the Distribution

System shall be specified in the User’s Connection Agreement.

DCC5.5 Specific metering arrangements depend on the load type, size and nature of

the installations being connected.


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DCC5.6 Specific Arrangements

DCC5.6.1 The specific arrangements for connection, including substation layout

requirements, User equipment, and Metering are set out clearly in the

Distribution Code and/ or Customer Service Manual as prepared by DSP(s)

and approved by ECRA. Users must comply with the provisions of the

documents relevant to their installations.

DCC6: Embedded Generator Requirements

DCC6.1 Introduction

DCC6.1.1 Distribution Connection Code 6 (DCC6) is applicable to all existing or

prospective Embedded Generators.

DCC6.1.2 In addition to meeting the requirements of DCC6, Embedded Generators shall

also comply with the requirements of the General Conditions, the Planning

Code, the Connection Conditions and other relevant sections of the

Distribution Code. Embedded Generators that are subject to Central Dispatch

shall additionally have to comply with the Saudi Arabian Grid Code (SAGC).

DCC6.1.3 If existing generating Plant does not comply with the standards set down in, or cannot comply (for technical or economic or other reasons) with the

requirements of this section, the Generator shall seek derogation from the

provision from ECRA.

DCC6.1.4 The Generator shall initiate discussions at a sufficiently early stage in design to allow DSP(s) to examine the impact of the Generating Unit(s) on the Distribution System.

DCC6.1.5 DSP(s) may refuse permission for the connection of a Generating Unit at a

point on the Distribution System or require revision to design or technical

parameters of the generation unit, or impose certain restrictions in order to

ensure that security and quality of supply standards as specified in DPC2 are

maintained. In such instances, DSP(s) shall provide sufficient supporting

information to justify the refusal or the required revisions.

DCC6.2 Specific Rules for Embedded Generators

DCC6.2.1 The integrity of the Distribution System and the security and quality of supply

to existing Users shall not fall below standard as a result of Generators

operating in parallel (synchronized) with the Distribution System. Conditions

for operation shall guarantee the safety of

- members of general public


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- personnel

- distribution equipment

Supply quality to other Customers shall not fall below standard as a result of

the presence or operation of Generating Units.

DCC6.2.2 Generating Units connecting to the Distribution System and operating in

parallel with, or which are capable of being operated in parallel with the

Distribution System, shall comply with the relevant DSP(s) document. This

document sets out the conditions with which Generating Units operating in

parallel with the Distribution System shall comply.

DCC6.2.3 Protection conditions and requirements are to protect the Distribution System.

The Generator is responsible for Protection of its personnel and equipment and

the efficient operation of its Generating Unit.

DCC6.2.4 Where a Generating Unit is to be installed on premises, DSP(s) shall be

informed. DSP(s) shall have the right to inspect generating installations to

ensure that the requirements are met. In some cases DSP(s) may require a

demonstration by operation of the Generator. Such demonstrations shall be by

agreement with the User.

DCC6.3 Provision of Information

DCC6.3.1 Information Required from Embedded Generators

Embedded Generators shall provide to DSP(s) information on (a) the

Generating Plant and (b) the proposed interface arrangements between the

Generating Plant and the Distribution System. The information required by

DSP(s) before entering into an agreement to connect any Generating Plant to

the Distribution System is shown below.

(a) Embedded Synchronous Generator Plant Data

(i) Terminal Volts (kV)

(ii) Rated kVA

(iii) Rated kW

(iv) Maximum Active Power sent out (kW), Reactive Power

requirements (kVAR)

(v) Type of Generating Plant - synchronous, asynchronous, etc.

(vi) Type of prime mover

(vii) Anticipated operating regime of generation e.g. Continuous,

intermittent, peak lopping (viii) Fault Level Contribution - a calculation sheet showing the


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fault current available from the Generators due to a metallic three-phase short circuit at the main incoming Circuit Breaker when all the Generators are operating. Account should be taken of any large motors in the installation (ref: IEC909)

(ix) Method of voltage control

(x) Generator transformer details, as applicable; and

(xi) Requirements for Top-up Supplies and/or Standby Supplies

Details will also be required on the following parameters:

(i) Inertia Constant MW sec//MVA (whole machine)

(ii) Stator Resistance

(iii) Direct Axis Reactance Sub-transient Synchronous

(iv) Time Constraints: Direct Axis Sub-transient

(v) Zero Sequence Resistance

Reactance (vi) Negative Sequence Resistance

Reactance

(vii) Generator Transformer

Resistance Reactance MVA Rating

Tap arrangement

Vector Group Earthing

(viii) Plant and Other Equipment

Details:

(a) A comprehensive schedule of installed new equipment

including details of Disturbing Loads is required.

(b) Interface Arrangements

(i) The means of synchronization between DSP(s) and User;

(ii) Details of arrangements for connecting with earth that part of

the Generating Plant directly connected to the Distribution

System;

(iii) The means of connection and disconnection which are to be

employed; and

(iv) Precautions to be taken to ensure the continuance of safe

conditions if any earthed neutral point of the Generators System

operated at High Voltage become disconnected from earth.

(b) Embedded Power Park Module Plant data

(i) Terminal Volts (kV)


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(ii) Number of inverter and for each of them

(iii) Rated kVA

(iv) Rated kW

(v) Maximum Active Power sent out (kW), Reactive Power requirements

(kVAR)

(vi) If applicable, number, surface and orientation of PV panels

(vii) Anticipated operating regime of generation e.g. continuous,

intermittent, peak lopping

(viii) Fault Level Contribution – a calculation sheet showing the fault

current available from the Generators due to a metallic three-phase

short circuit at the main incoming Circuit Breaker when all the

Generators are operating. Account should be taken of any large motors

in the installation (ref: IEC909)

(ix) Method of voltage control

(x) Generator transformer details, as applicable; and

(xi) Requirements for “top-up supplies” and/or “standby supplies”.

DCC6.3.2 The details of information required will vary depending on the type and size

of the Generating Unit or the point at which connection is to be made to the

Distribution System. This information shall be provided by the Generator at

the reasonable request of DSP(s).

DCC6.3.3 DSP(s) will use the information provided to model the Generating Unit to

determine a technically acceptable method of connection. If DSP(s) reasonably

concludes that the nature of the proposed connection or changes to an existing

connection requires more detailed analysis then further information than that

specified in DCC6.3.1 may be required.

DCC6.3.4 Additional information may be required from Embedded Generators with a

Registered Capacity greater than 2MW or connected at a voltage level above

13.8kV

(a) Technical Data

(i) Generating Plant information (impedance per unit on rating)

Type of prime mover

Rated MVA

MW

Type of excitation system

(ii) Automatic Voltage Regulator (AVR):

A block diagram for the model of the AVR system including the

data on the forward and feedback gains, time constants and

voltage control limits.

(iii) Speed Governor and Prime Mover Data:


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A block diagram for the model of the Generating Plant governor;

detailing the governor fly ball, if applicable, and system control

and turbine rating.

(iv) Generator Excitation System.

(b) Capacity and Standby Requirements

(i) Registered Capacity and minimum generation of each

Generating Unit and power station in MW.

(ii) Generating unit and power station auxiliary Demand (Active

Power and Reactive Power) in MW and MVAr, at Registered

Capacity conditions.

(iii) Generating unit and power station auxiliary Demand

(Active and Reactive Power) in MW and MVAR, under

minimum generation conditions.

DCC6.3.5 In normal circumstances the information specified above will enable DSP(s)

to assess the connection requirements. Occasionally additional information

may be required. In such circumstances, the information shall be made

available by the Generator, at the reasonable request of DSP(s).

DCC6.4 Information Provided by DSP(s)

DCC6.4.1 DSP(s) shall prepare a statement as per DCC3.2 for Generators applying for

connection to the Distribution System.

DCC6.4.2 Where Generator paralleling or power export is intended the following

additional information shall be provided including:

(a) Interface Protection settings

(b) Equipment, cabling, switchgear, metering requirements

(a) Substation site and building requirements (dimensions, access,

planning permission, Earthing, lighting and heating). DCC6.5 Technical Requirements

DCC6.5.1 Generating Plant Performance Requirements

(a) All centrally dispatched Generators shall comply with the relevant

sections of the Saudi Arabian Grid Code (SAGC).


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(b) For Embedded Generators not subject to Central Dispatch the

electrical parameters to be achieved at the Generating Unit terminal

shall be specified by DSP(s) with the offer for connection.

(c) Protection associated with Embedded Generating Plant shall be

required to co-ordinate with the Distribution System Protection

regarding:

(i) Clearance times for fault currents.

(ii) Co-ordination with auto recloser requirements. (iii) Protection settings of the controlling Circuit Breaker.

Protection settings shall not be changed without a written agreement

from DSP(s). These Protection requirements are additional to normal

interface Protection requirements of the User.

(d) User’s developments shall meet the following power quality

requirement assessed at the Connection Point:

harmonic distortion shall be not more than permitted in the most

recent approved version of IEC.61000-3-6;

voltage fluctuations shall be within the limits defined in the most

recent approved version of IEC 61000-3-7;

phase unbalance of currents shall not exceed 1%.

Any embedded generator except Stand-by Generators must be designed for

normal operation in the presence of disturbances at the levels that can be

expected, as indicated in the above standards.

The following table applies to harmonic penetration:

Table DCC6.1: Generator Total Harmonic Voltage Distortion Limits


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The Planning Levels for the Total Harmonic Distortion are

THDup to 33kV = 6,5% and THDabove 33kV= 3 %

Additionally, no direct current (DC) shall be injected into the grid.

DCC6.6 Rate of Change of Frequency

All Embedded Synchronous Generating Units must be capable of

withstanding any rate of change of frequency up to 1Hz/s without

disconnection from the network other than when triggered by loss of mains

protection. The rate of change of frequency shall be measured over a sliding

500ms time period.

All Embedded Power Park Modules must be capable of withstanding a rate

of change of frequency in excess of 1Hz/s without disconnection from the

network other than when triggered by loss of mains protection. The rate of

change of frequency shall be measured over a sliding 500ms time period. (For

the avoidance of doubt, this requirement is set so that Power Park Modules

will not trip before Synchronous Generating Units to avoid worsening

frequency stability of the

DCC6.7 Islanding Disconnection

DCC6.7.1 It is conceivable that a part of the Distribution System, to which an Embedded

Generation Unit is connected can, during emergency conditions, become

detached from the Total System. Unless, in the reasonable opinion of the

appropriate DSP, a Power Producer’s Plant can remain connected and

continuously control voltage and frequency within the limits set down in this

Distribution Code, it must detect any condition whereby it is isolated from the

Total System and cease to supply energy to Customers (other than itself) within

500ms. For the avoidance of doubt, unless within an area stablished by

adequate levels of Synchronous generation, Asynchronous Generating Units

must trip within 500ms of becoming islanded.” The DSP will provide advice

on methods/sliding time period of islanding protection which are deemed

acceptable.

DCC6.7.2 If no facilities exist for the subsequent automatic resynchronization with the

rest of the Distribution System then the Embedded Generators shall under

DSP(s) instruction ensure that the Generating Plant is disconnected for

resynchronization.

DCC6.8 Energisation and Ramping of Generating Units

DCC6.8.1 Synchronization of Synchronous Generating Units Unless proven facilities


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exist for the automatic resynchronization of Synchronous Generating Units with the rest of the Distribution System then the Embedded Power Producers shall ensure that their Synchronous Generating Plant is disconnected and, under the DSP’s instruction, prepared for manual resynchronization.

DCC6.8.2 Synchronous Embedded Generating Units shall not be reconnected to the Distribution System before the Total System Frequency is within the range 58.8Hz – 60.05 Hz and before the voltage at the Connection Point has remained within the range 95% - 105% of nominal for a minimum of 60 seconds.

DCC6.8.3 Synchronization of an Embedded Generating Unit with the Distribution System should not create a transient voltage variation of more than 4%.

DCC6.9 Energisation / ramping of Embedded Power Park Modules

DCC6.9.1 Following emergency or planned disconnection from the Distribution System

(other than as part of normal climatic operation of an Embedded Power Park

Module) each Embedded Power Park Module with a Registered Capacity of

2MW or more, and which is not Centrally Dispatchable, shall not be re-

connected to the Distribution System without the prior permission of the DSP,

who may seek permission from the TSP.

DCC6.9.2 Embedded Power Park Modules shall not reconnect or increase output when

the System Frequency is above 60.2Hz.

DCC6.9.3 For Embedded Power Park Modules, facilities shall exist and be switchable in

or out, whereby a settable power ramping rate may be applied to the Active

Power output so that the output shall not be increased with a gradient above

the set value. Unless otherwise agreed with the DSP a value of 10% of the

Registered Capacity per minute shall be set. The DSP shall confirm any

different value in the Connection Agreement and notify any change in the

value from time to time. The DSP shall also confirm whether the facility shall

initially be switched in or out of service and may instruct a change in this from

time to time.

DCC6.10 Active Power Performance

DCC6.10.1Table DPC2.1 indicates the periods for which Generating Units must tolerate

Frequency deviations on the Saudi Arabian Total System.

DCC6.10.2All Embedded Generating Units with a Registered Capacity of 2MW or more,

must be capable of continuously supplying Output in accordance with the

power curve (as set out in the Connection Agreement) within the System

Frequency range 58.8 Hz to 60.5 Hz. For Generating Units seeking connection


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after [30th June 2017] there must be no reduction in Output within the

Frequency range 58.8 Hz to 60.5 Hz whilst Frequency is falling. Within the

Frequency range 58.8 Hz to 57.0 Hz, any decrease in Output must not be more

than pro-rata with any decrease below nominal Frequency. In the case of

Embedded Renewable Resource Generating Units the Output is dependent

upon the availability of Renewable Resource, therefore when assessing

compliance with the requirements of this paragraph, the maintenance of (or

change of) Output will be compared to values stated in the power curve or

table as specified/set out in the Connection Agreement.

DCC6.10.3Below 57.0Hz Power Producers may disconnect to protect their Generating

Units and associated equipment.

DCC6.11 Active Power Control

DCC6.11.1All Embedded Generating Units with a Registered Capacity of 2MW or more

approved for connection after [1st June 2017] shall be capable of operation in

Frequency Sensitive Mode. When in Frequency Sensitive Mode the following

control facility shall be operational with settings agreed with the DSP.

DCC.6.11.2The Frequency Sensitive Mode Active Power controller shall permit the

setting of separate Deadbands and Droops for Frequencies above and below

60Hz. Deadbands shall be settable with a lower limit between 59.0 Hz and

60.0 Hz in steps of 0.05 Hz and an upper limit between 60.0 Hz and 61.0 Hz

in steps of 0.05 Hz. The Active Power Droop shall be adjustable within the

range 2% and 8% is steps of a maximum of 1%. Unless otherwise instructed

by the DSP, Deadbands shall be set at +0.2HZ and -0.2Hz of 60Hz and Droop

at 4%.

DCC6.11.3With these settings, Generating Units shall be capable of regulating their

Active Power Output in the frequency range 57HZ to 59.8Hz and 60.2Hz to

62.5Hz through modulation of the Active Power as a function of frequency

deviations below 59.8 Hz or above 60.2Hz respectively. Figure 6.9.1 shows

the requirement graphically.


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Graphic representation of the “Governor” function for both Synchronous and

Asynchronous Generating Units

DCC6.11.4The Active Power output of the Embedded Renewable Resource Generating

Units with Registered Capacity of 2MW or greater shall be controllable as

long as technically feasible based on the available Renewable Resource

energy.

DCC6.11.5Each Power Park Module with a capacity greater than 2MW shall be

controllable remotely by the DSP, shall obey a properly formatted Dispatch

Instruction received from the DSP and shall be deemed to have complied if its

Active Power matches the instructed amount to the extent that prevailing

climatic conditions permit (as further specified in point (iii) of this clause).

Embedded Power Producers shall ensure that the following interface control

and performance requirements are met in respect of each of their Renewable

Resource Generating Units:

(i) capability to receive Dispatch Instructions through an automatic remote

control or SCADA system, to switch in or out Frequency Sensitive Mode

based upon Active Power Delta Regulation, to adopt a set point of Active

Power output, to set an Absolute Active Power Limitation and to switch

in or out and control ramp rate by setting an Active Power Gradient;

(ii) automatic confirmation, enactment of Dispatch Instructions received

further to DCC 6.9 (i) and confirmation that the instructed action has been

achieved;

(iii) with respect to accuracy of the set point adjustment and the resulting

control action, there shall not be any deviation of more than 2% of the set

point value or by 0.5% of the rated power, whichever provides the closer

tolerance and the action shall be completed in less than 10 minutes after

receipt of the Dispatch Instruction. In making such assessment due regard

shall be taken of the available Renewable Resource and the power curve

as specified/set out in the Connection Agreement.


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DCC6.12 Reactive Power capacity and controllability

DCC6.12.1 Embedded Generating Units with Registered Capacity less than 2MW:

(i) Embedded Generating Units with a Registered Capacity less than 2MW shall as a

minimum be able to control Power Factor to a value agreed with the DSP. The

Generating Unit’s Reactive Power capability must as a minimum to lie within the

range 0.95 absorbing to 0.95 generating when the Generating Unit is operating

full Active Power Registered Capacity. Embedded Generating Units approved for

connection after [Date] shall additionally be equipped to vary their Reactive Power so as to control voltage local to the Embedded Power Producer’s facility,

but nothing shall compel a Power Producer to operate beyond the equipment

rating or stability limits set down in the relevant Connection Agreement.

(ii) Where the Generating Unit is to be operated on a fixed Power Factor, this will be

stated in the Connection Agreement and may be varied from time to time by the

DSP within the range stated above or as further agreed in the Connection

Agreement (as allowed for in DGC5.2).

(iii) For Embedded Power Park Modules of less than 2MW, when the Active Power

output is below 20% of Registered Capacity, the Embedded Power Park Module

will maintain its absolute Reactive Power below 4% of Registered Capacity for

nominal voltage unless equipped to perform as a Power Park Module of larger

size. Deviation of Reactive Power Output due to voltage deviation is accepted on

a proportional basis.

(iv) Additionally, the Embedded Power Park Modules with a Registered Capacity

greater than 200kW and less than 2MW will have the capability to maintain their

power factor below 0.95 lagging if the voltage at Connection Point is below 90%

of nominal voltage and below 0.95 leading if the voltage at Connection Point

above 110% of nominal voltage. Between these limits of voltage, power factor

should be linearly adapted to reach unity power factor at nominal voltage. The

figure below illustrates in the hatched area the acceptable range of operation. This

chosen operating mode fixed power factor or power factor as a function of the

voltage is defined by the DSP in the Connection Agreement.

DCC6.12.2 Generators having a Registered Capacity greater than 2MW:

(i) Embedded Synchronous Generating Units

a. Each Embedded Synchronous Generating Unit with a Registered Capacity

of 2MW or greater must be capable of supplying its Registered Capacity

in MW at any point between the limits 95% Power Factor (absorbing) and

95% Power Factor (generating) measured at the Connection Point when

voltage is nominal. Deviation from these ranges due to voltage deviation

is accepted on the basis set down in Figure 6.10.3.

b. Each Embedded Synchronous Generating Unit with a Registered Capacity

of 2MW or greater shall be equipped with high-speed response Excitation

System with a continuously and fast-acting Automatic Voltage Regulation

(AVR) system targeted at controlling the Generating Unit terminal

voltage. The AVR shall be designed and operated to maintain the steady-


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state terminal voltage within ± 0.5% of the set point in the normal voltage

range specified in DPC2.1 without instability over the entire operating

range of the Generating Unit. Power Producers shall not disable this

automatic voltage control mode without prior approval of the DSP.

c. Each embedded Synchronous Generating Unit with a Registered Capacity

greater than 2MW shall be required with VAr limiting equipment.

(ii) Embedded Power Park Modules with Registered Capacity of 2MW or greater:

a. Each Embedded Power Park Module with Registered Capacity of 2MW

or greater when the voltage is nominal shall be capable of absorbing or

supplying Reactive Power Output at the Connection Point and within the

range Q= [-0.33pu, +0.33pu] of Registered Capacity (assessed in MW for

Active Power). This requirement applies when the level of output is above

20% of rated power, unless an alternative value of Active Power threshold

is agreed upon by the DSP in the Connection Agreement (as allowed for

in DGC5.2). The required Reactive Power performance is control mode

dependent as shown in Figure 6.10.1. Figure 6.10.1 also shows the

required performance when the level of Active Power output is below

20%. Deviation from these ranges due to voltage deviation is accepted on

the basis set down in Figure


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Minimum Reactive Power requirement for Embedded Power Production Modules ≥ 2MW

depending upon the selected control modes

Per Unit Reactive Power at the Connection Point based upon 1 PU Active Power rating

b. For values of Active Power Output below 20% of Registered Capacity,

each Embedded Power Park Module with Registered Capacity of 2MW

or greater shall be capable of limiting its Reactive Power Output at the

Connection Point within the range Q=[-0.05 to +0.05] of rated power

(based upon nominal voltage at the Connection Point). The

implementation of these limits shall be instructed by the DSP and any

alternative to the 20% value of Active Power threshold may be agreed by

the DSP in the Connection Agreement. Deviation from these ranges due

to voltage deviation is accepted on a basis agreed by the DSP in the

Connection Agreement.

c. Power Park Modules with a Registered Capacity of 2MW or more shall

not consume on average more Reactive Power in the 10 seconds following

a disturbance on the Distribution System than they did on average in the

10 minutes before the occurrence of the disturbance. Where a Power Park

Module is supporting the Distribution System voltage through Reactive

Power export, it shall not draw Reactive Power during or immediately

following the disturbance.

d. Each Embedded Power Park Module with a Registered Capacity greater

than 2MW shall be equipped to automatically control its Reactive Power

during normal operation according to a control mode and settings advised

from time to time by the DSP. The initial control mode and settings will

be provided in the Connection Agreement. Each Embedded PPM shall be

capable of the following control modes:

i. Voltage Control mode;


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ii. Reactive Power control mode;

iii. Power Factor control mode;

e. The Voltage Control mode shall be targeted to maintain the steady-state

voltage to a set-point value measured at the Connection Point. The

tolerance to be achieved is ± 0.5% of the nominal voltage.

f. In the event that voltage exceeds the normal range specified in DPC2.1

and where Reactive Power or Power Factor control mode are employed,

the Generating Unit must switch as an emergency to Voltage control mode

and target both Reactive Power and then Active Power to return the

voltage to within the range specified in DPC2.1.

g. In the event that the above emergency action by the Generating Unit

cannot achieve a Voltage within a limited time excursion value the

Generating Unit must trip as shown in Figure 6.10.3.

h. When the Voltage has been stabilised to within the normal range for 10

minutes continuously, the Generating Unit shall revert to the normal

control mode as previously instructed by the DSP.

Deployment of modes of Reactive Power control for Power Park Modules (1.05pu -0.95pu

is normal voltage range on Distribution System)

DCC6.13 Communication

DCC6.13.1 Each Embedded Generator shall ensure that it complies, in respect of each

Generating Unit within its facility, with [Schedule###] of this Code, which

details the destination, list and format of signals required to enable information

and normal and emergency control of the GU. The DSP will have the right to

test performance of these signals and the DSP may withhold a Connection

Certificate (Temporary or Final) or replace a Final Certificate with a Limited

Performance Certificate until such time as the problem has been rectified and

the communication is proven to work.


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DCC6.13.2 Each party (TSP, DSP and SSEC) empowered to issue and receive signals

from Users is required [by the terms of its Licence] to have proper regard for

the security of the System from cyber threats and all control centres, DSP(s)

and Users of the Distribution System are required to cooperate to the fullest

extent in establishing and maintaining procedures and practices aimed at

reducing such risks drop to between 70% and 80% of the nominal voltage for

a period of up to 300 millisecond in any one phase or combination of phases,

followed by a period of one (1) second where voltage may vary in the range

80-110% of the nominal voltage.

DCC.6.13.3 In the event of a step change in voltage each Embedded Power Park Module

of 2MW or greater shall remain connected to the Distribution System as

specified in the Figure

DCC6.14 Fault Ride Through

DCC6.14.1 Under transient conditions, Embedded Generators with a Registered Capacity

greater than 200kW and less than 2MW must be capable of withstanding

Faults on the Distribution System which may cause the voltage at the

Connection Point to drop to between 70% and 80% of the nominal voltage for

a period of up to 300 millisecond in any one phase or combination of phases,

followed by a period of one (1) second where voltage may vary in the range

80-110% of the nominal voltage.

DCC6.14.2 In the event of a step change in voltage each Embedded Power Park Module

of 2MW or greater shall remain connected to the Distribution System as

specified in the Figure


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time based requirement for a Power Park Module of Registered Capacity ≥ 2MW to

remain Connected to the Distribution System during periods of reduced

voltage on that System

DCC6.15 Short-Circuit Contribution

DCC6.15.1 It is preferable that in the case of single-phase to earth faults, the short-circuit

current contribution of Embedded Generating Units shall not exceed the short-

circuit current in each phase occurring during a solid 3-phase fault. This is to

ensure that equipment ratings are not exceeded. In the event that calculation

by a User shows that single-phase to earth fault-current will be higher than the

phase currents during a 3-phase fault, the Power Producer must draw the

matter to the attention of the DSP who will assess the situation on a case-by-

case basis and advise the Power Producer. In the event that the DSP’s

assessment still shows that action is needed by the Power Producer, it will be

the Power Producer’s responsibility to provide a technically sound solution in

line with Good Industry Practice.

DCC6.15.2 For three-phase Embedded Generators, the 1-phase short-circuit current shall

not be below 60% of the 3-phase short-circuit current in order to facilitate

protection selectivity.

DCC6.15.3 Asynchronous Generating Units (including invertors) above 2MW may be

required to make a contribution to fault-level in order to ensure the proper

operation of system protection. The minimum contribution will be specified

in the Connection Agreement as a current and phase-angle to the system

voltage which maybe on a sliding scale with retained System voltage. (as


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allowed for in DGC5.2).

DCC6.16 Black Start Capability

DCC616.1 Embedded Synchronous Generators with a Registered Capacity greater than 2MW shall notify DSP(s) if its Generating Plant has a restart capability without connection to an external power supply.

DCC6.16.2 Embedded Asynchronous Generating Units (Power Park Modules) will not be required to provide Black Start capability and will not be used as part of any Black Start plan until a stable Synchronous system or part thereof has been established.

DCC6.17 Generating Plant Commissioning Tests

DCC6.17.1Where the Generating Plant requires connection to the Distribution System in

advance of the Commissioning date, for the purposes of testing, the Generator

shall comply with the requirements of the Connection Agreement. The

Generator shall provide DSP(s) with a Commissioning programme, approved

by DSP(s) if reasonable in the circumstances, to allow Commissioning Tests

to be co-ordinated.


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PART 5: OPERATION

Contents

DOC1 Demand Forecasting

DOC2 Operational Planning

DOC3 Demand Control

DOC4 Operational Communications and Liaison

DOC5 Event Reporting

DOC6 System Tests

DOC7 Monitoring Testing and Investigation

DOC8 Safety Co-Ordination

DOC1: Demand Forecasting

DOC1.1 Introduction

DOC1.1.1 In order for DSP(s) to operate the Distribution System efficiently and to ensure

maximum system security and system stability, there is a need for those Users

specified in DOC1.2 to provide loading and generation output information to

DSP(s).

DOC1.1.2 Demand forecasting specifies the information to be provided to DSP(s) by

other Users of the Distribution System so that these requirements can be met.

DOC1.1.3 Demand forecasting sets out the Demand forecasting and the generating Plant

output information to be provided by Users to enable DSP(s) to operate the

Distribution System; and specifies the information to be provided by Users to

the DSP(s).

DOC1.1.4 Where Demand data is required from the User, this means the MW Demand

of electricity at the Connection Point. DSP(s) may in certain cases specify that

the Demand data shall include the MVAR Demand.

DOC1.1.5 The means of providing the information to DSP(s) and its confirmation

includes any non-transitory written form, or any other suitable means of

electronic transfer which enables the recipient to retain information. DOC1.2 Scope

DOC1.2.1 Demand forecasting applies to the following Users of the Distribution System

(a) Major Customers connected to the Distribution System and Medium

Voltage Customers where DSP(s) considers it appropriate.

Embedded Power Producers with a Registered Capacity greater 2MW and whose

Generating units are not subject to Central Dispatch.


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DOC1.3 Capability of receiving Dispatch Instructions

DOC1.3.1 Dispatch Instruction given by the DSP to a non-Renewable Resource

Generator for each Embedded Generating Unit above 2MW may involve a

change in the Active Power Output, a change in the Reactive Power Output,

Synchronizing and de-synchronizing time (if appropriate), a change to the

mode of operation, or to provide one or more of the contracted System

Services.

DOC1.3.2 Dispatch Instruction to Renewable Resource Generating Units with a

Registered Capacity greater than 2MW will be given by the TSP through the

Saudi Sustainable Energy Control Center.

DOC1.4 Information Flow and Co-Ordination

DOC1.4.1 DSP(s) shall co-ordinate Demand Forecast information for each Bulk Supply

Point to meet the requirement of the Saudi Arabian Grid Code (SAGC).

DSP(s) shall aggregate forecast information provided by Users, where

appropriate, and provide forecast information to the TSP where Demand, or

change in Demand, is greater than 10MW at any Connection Point.

DOC1.4.2Information from Embedded Power Producers for Generating Units in the

Distribution System, which are not subject to Central Dispatch, shall be

provided where specified to DSP(s). Production Embedded Generators with a

Registered Capacity greater than 200kW may also be required to supply

information.

DOC1.4.3 Information regarding Renewable Resource Generating Units, shall be

provided to DSP(s) (on request) through the Saudi Sustainable Energy Control

Center..

DOC1.5 Demand Forecast Data

DOC1.5.1 Major Customers shall provide to DSP(s) information regarding Demand and

planned shutdowns for specified future periods. This shall be provided on an

annual basis when requested by DSP(s).

DOC1.6 Information regarding Output and planned shutdowns

DOC1.6.1 Generating Units with a Registered Capacity up to 2MW need not provide

DSP(s) with information regarding Output and planned shutdowns for

specified future periods unless specifically requested to do so by the DSP. If so

requested, Power Producers shall comply with a reasonable timeframe for the

provision of the data as set by the DSP. The DSP will not require such

information from Power Producers with Renewable sourced Generating units


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with a Registered Capacity less than 200kW.

DOC1.6.2 Generating Units with a Registered Capacity above 2MW not based upon

Renewable Resource and not subject to Central Dispatch shall provide DSP(s)

with information regarding Output and planned shutdowns for specified future

periods. This shall be provided on an annual basis according to a timetable set

by DSP(s).

DOC1.6.3 Generating Units with a Registered Capacity above 2MW based upon

Renewable Resource and not subject to Central Dispatch shall provide SSEC

with information regarding Output and planned shutdowns for specified future

periods. This shall be provided on an annual basis according to a timetable set

by SSEC which shall have regard to the timetable set down by the TSP in the

SAGC.

DOC1.6.4 Generating Units with a Registered Capacity above 2MW (whether based upon

Renewable Resource or otherwise) and subject to Central Dispatch shall

provide TSP(s) with information regarding Output and planned shutdowns for

specified future periods. This shall be provided on an annual basis according

to a timetable set by down in the SAGC.

DOC2: Operational Planning

DOC2.1 Introduction

DOC2.1.1 Operational Planning;

(a) Sets out the operational planning procedure and typical timetable for

the co-ordination of outage requirements for Plant and apparatus to be

provided by Users to enable DSP(s) to operate the Distribution System

and

(b) Specifies the information to be provided by Users to DSP(s) to allow

it to comply with the Saudi Arabian Grid Code (SAGC).

DOC2.1.2 The means of providing the information to DSP(s) and its confirmation

includes any non-transitory written form, or any other suitable means of

electronic transfer which enables the recipient to retain information.

DOC2.1.3 In order for the DSP(s) to fulfill the requirements of DOC2 it should be noted that the information set out in the Saudi Arabian Grid Code (SAGC), to be

provided by the TSP will form the basis of operational planning under DOC2.

DOC2.2 Scope

DOC2.2.1 DOC2 applies to the following Users of the Distribution System:


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(a) Major Customers connected to the Distribution System where DSP(s)

considers it appropriate;

(b) Embedded Power Producers with Generating Units connected to the

Distribution System

DOC2.3 Provision of Information

DOC2.3.1 Information on Embedded Generating Plant with a Registered Capacity

greater than 2MW and which is not subject to Central Dispatch (including

Customers with CHP and Customers with Auto-production) shall be provided,

where specified, directly to DSP(s).

DOC2.3.2 Information on Renewable Resource Generation shall be provided, where

specified, to DSP(s) through the Saudi Sustainable Energy Control Center.

DOC2.3.3 Centrally Dispatched Generating Units shall comply with the requirements of

the Saudi Arabian Grid Code (SAGC). Information shall be provided directly

to the TSP.

DOC2.4 Time scales and Data

DOC2.4.1 Detailed implementation of data gathering and timescales shall be determined

by DSP(s) and each User. Due recognition shall be given by DSP(s) to

voltage levels and capacities of Plant and apparatus when assessing

information requirements.

DOC2.4.2 The information may be required for different timescales as may be

determined by DSP(s) planning needs.

DOC2.5 Information from Embedded Generators

DOC2.5.1 Information from Embedded Generating Plant with a Registered greater than

2MW and not subject to Central Dispatch shall include details of Planned Outages for maintenance or other purposes as well as the expected time of return of service.

DOC2.5.2 Information regarding the details of Planned Outages for maintenance or other purposes as well as the expected time of return of service of Renewable Resource Generation with a Registered Capacity greater than 2MW, will be given by to the DSP on annual basis through the Saudi Sustainable Energy Control Center

DOC2.5.3 The Generator shall not synchronize without first obtaining permission from

DSP(s) unless prior agreement has been reached with DSP(s). Automatic

resynchronization as defined is DCC6.8 is a prerequisite for such an agreement.

DOC2.6 Information to Users


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DOC2.6.1 DSP(s) shall advise Major Customers or Generators who may be significantly

affected by particular outages of Distribution Plant and apparatus, of the likely

dates and duration of the outages. If there are objections from Users these shall

be considered by DSP(s) and alternative arrangements proposed if possible.

DOC3: Demand Control

DOC3.1 Introduction

DOC3.1.1 DOC3 is concerned with provisions to be made by DSP(s) or Users of the

Distribution System, in certain circumstances, to permit reductions in

Demand. Reductions would be permitted:-

(a) In the event of insufficient Generating Plant and transfers from external

interconnections are not available to meet Demand;

(b) To avoid disconnection of Customers; or

(c) (c) In the event of breakdown and/or operating problems (such as in respect

of system Frequency, system voltage levels or system thermal overloads) on

any part of the Transmission or Distribution System.

DOC3.1.2 The Demand control procedures ensure that hardship to Users and Customers

is minimized and that in so far as is practicable, all parties affected are treated

equitably.

DOC3.1.3 DOC3 deals with the following means of reducing Demand:

(a) automatic low Frequency or voltage Demand disconnection;

(b) Customer Demand reduction including Voltage Reduction;

(c) Customer Demand management initiated by Suppliers or other parties,

other than following an instruction by DSP(s) or TSP;

(d) Customer Demand reduction instructed by DSP(s) or TSP ;and

(e) Emergency manual Demand disconnection.

The term Demand Control is used to describe any or all of these methods of

achieving a Demand reduction.

DOC3.1.4 Where Demand Control is exercised by DSP(s) or the TSP it shall be done in

a manner that in so far as reasonably practicable does not discriminate against

any Customer or supplier and shall use reasonable endeavors to ensure that

the burden is shared fairly among Customers. Exemptions may apply to vital

and priority Customers as defined in the Distribution load shedding criterion/

plan submitted by DSP(s) and approved by ECRA.


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DOC3.2 Scope

DOC3.2.1 DOC3 applies to DSP(s) and all Users of the Distribution System.

DOC3.2.2 Implementation of Demand Control by DSP(s) may affect all Customers of

Suppliers connected to the Distribution System and where applicable,

contractual arrangements between Suppliers and their Customers may need to

reflect this.

DOC3.3 Methods of Demand Control

DOC3.3.1 Customer Demand may be disconnected automatically at selected locations

in accordance with the requirements of the Saudi Arabian Grid Code, in the

event of a sudden fall in Frequency. Such an arrangement shall be carefully

coordinated as part of an overall scheme and may take into account any

operational requirements or essential load.

DOC3.3.2 Automatic disconnection by under voltage relay may be used discriminately to

disconnect load at 33kV or 13.8kV in order to maintain voltage within

acceptable limits, so as to avoid widespread load shedding.

DOC3.3.3 Deliberate reduction of voltage may be used to achieve a temporary reduction in load Demand.

DOC3.3.4 Deliberate reduction in system Frequency may also be used to achieve a

temporary reduction in load Demand in accordance with the Saudi Arabian

Grid Code (SAGC).

DOC3.3.5 Emergency manual load shedding may be carried out on the Distribution or

Transmission Systems for reasons of shortfall in supply or other reasons.

DOC3.3.6 In the event of a sustained period of shortfall then planned Rota load shedding

may be used to share the available power among affected Customers.

DOC3.4 Implementation of Demand Control

DOC3.4.1 Where a Demand Control is exercised by DSP(s) in order to safeguard the

Distribution System, DSP(s) shall liaise with and inform Users accordingly as

far as is practicable.

DOC3.4.2 Where Demand Control is exercised by DSP(s) on instruction or request from


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the TSP in order to safeguard the total System then DSP(s) is required to

respond to these requests promptly but shall liaise with and inform other Users

so far as is practicable.

DOC3.4.3 Procedures for load shedding including exemption policies, load shedding

Rota and Customer communications are contained in the Distribution load

shedding criterion/ plan approved by ECRA.

DOC4: Operational Communications and Liaison

DOC4.1 Introduction

DOC4 sets out the requirements for the exchange of information in relation

to Operations and/or Events on the Distribution System or the installation

of any User connected to the Distribution System which have had or

may have had, or will have or may have an Operational Effect on the

Distribution System or the installation of any other User.

DOC4.2 Scope

DOC4 applies to the following Users of the Distribution System:

(a) Major Customers connected to the Distribution System where DSP(s)

considers it appropriate;

(b) Embedded Generating Plant with a capacity greater than 2MW, or

according to CA/PPA between DSP and Generators.

DOC4.3 Procedure

DOC4.3.1 DSP(s) and Users connected to the Distribution System shall nominate persons

and/or contact locations and agree communication channels for the necessary

exchange of information to make effective the exchange of information

required by DOC4.

DOC4.3.2 SCADA equipment may be required at a User’s site for transmission of information and data to and from the DSP(s). The requirement to provide this

information shall normally be included in the relevant Connection Agreement.

DOC4.3.3 Information between DSP(s) and Users shall be exchanged on the reasonable

request of either party. The request may follow a specific Operation, or be in accordance with a prior agreement to exchange information on particular types

of Event. This does not preclude the voluntary exchange of information which

may be perceived as being relevant to the operation of the Distribution or User

Installation, in accordance with Good Industry Practice.

DOC4.3.4 DSP(s) shall notify the User of any Operation on the Distribution System (or

of any Operation on the Transmission System of which it has received notice)


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which, in the opinion of DSP(s), will have or may have an Operational Effect

on the installation of the User.

DOC4.3.5 A User shall notify DSP(s) of any Operation on the installation of that User

which will have or may have an Operational Effect on the Distribution

System.

DOC4.3.6 A notification under DOC4 shall include the name of the individual reporting

the Operation and, although it need not state the cause, shall be in sufficient

detail to describe the Operation and to enable the recipient reasonably to know

and consider the implications and risks arising there from. The recipient may

ask questions to clarify he notification.

DOC4.3.7 A notification under DOC4 shall be given as far in advance as possible to allow

the recipient to consider and assess the implications and risks arising.

DOC4.4 Significant Incidents

DOC4.4.1 Where an Event on the Distribution System has had or may have had a

significant effect on the User’s installation or where an Event in the User’s

installation has had or may have had a significant effect on the Distribution

System, DSP(s), in consultation with the User, shall deem the Event to be a

Significant Incident. Significant incidents shall be reported in writing to the

affected party in accordance with the provision of DOC5.

DOC4.4.2 Significant Incidents shall include Events which result in, or may result in, the

following:

(a) Voltage outside statutory limits;

(b) System Frequency outside statutory limits; or

(c) System stability failure.

DOC5: Event Reporting

DOC5.1 Introduction

DOC5.1.1 DOC5 sets the requirements for reporting in writing those Events deemed to

be “Significant Incidents” under DOC4.

DOC5.1.2 DOC5 also provides for the joint investigation of Significant Incidents by the

Users involved.

DOC5.2 Scope

DOC5.2.1 DOC5applies to the following Users of the Distribution System:

a) Major Customers connected to the Distribution System where DSP(s)

considers it appropriate; b) Embedded Generating Plant with a capacity greater than 2 MW, or according


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to CA/PPA between DSP and Generators

DOC5.3 Procedures

DOC5.3.1 DSP(s) and each User specified in DOC5.2.1 shall nominate officers and

establish communication channels to ensure the effectiveness of DOC5.

Such officers and communication channels may be the same as those

established under DOC4.

DOC5.3.2 Communication shall, as far as possible, be direct between the User and

DSP(s). This does not, however, preclude communication with the Users

nominated representative.

DOC5.3.3 In the case of an Event that has been reported to DSP(s) under DOC4 and subsequently has been determined by DSP(s) to be a Significant Incident, a

written report shall be given to DSP(s) by the User in accordance with DOC5.

DOC5.3.4 In the case of an Event that has been reported to the User under DOC4 and subsequently has been determined by DSP(s) to be a Significant Incident, a

written report shall be given to the User by DSP(s) in accordance with DOC5.

DOC5.3.5 A Report shall be in writing or in electronic form and shall be sent to DSP(s)

or User, as the case may be. It shall contain confirmation of the notification

given under DOC4 together with more details relating to the Significant

Incident including information which has become known relating to the

Significant Incident since the notification. The report shall, as a minimum,

contain those matters specified in DOC5.

DOC5.3.6 A report under DOC5 shall be given as soon as reasonably practical after the

notification under DOC4.

DOC5.4 Joint Investigations

DOC5.4.1 Where a Significant Incident has been declared and a report submitted under

DOC5 either party or parties may request in writing that a joint investigation

be carried out.

DOC5.4.2 The composition of such an investigation panel shall be appropriate to the

incident to be investigated and agreed by all parties involved.

DOC5.4.3 A joint investigation shall only take place where all parties affected by it agree

to it. The form and rules of, and procedures for, and all matters relating to the

joint investigation shall be agreed at the time of a joint investigation and in

the absence of agreement the joint investigation shall not take place.

DOC5.5 Matters to be Included in a Written Report of a Significant Incident

DOC5.5.1 Matters applicable to DSP(s) and Embedded Generators are as follows:


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(a) date and time of Significant Incident;

(b) location;

(c) equipment involved;

(d) brief description of Significant Incident;

(e) details of any Demand Control undertaken;

(f) conclusions and recommendations if applicable

DOC5.5.2 Matters applicable to DSP(s) are as follows:-

Effect on Users where appropriate:

(a) Duration of incident; and

(b) Estimated date and time of return to normal service.

DOC5.5.3 Matters applicable to Embedded Generators as follows:

(a) date and time of Significant Incident;

(b) location;

(c) equipment involved;

(d) brief description of Significant Incident;

(e) details of any Demand Control undertaken; (f) conclusions and recommendations if applicable

DOC6: System Tests

DOC6.1 Introduction

DOC6.1.1 DOC6 sets out the responsibilities and procedures for arranging and carrying

out System Tests which have or may have an effect on the Systems of DSP(s)

or Users. System Tests are those which involve either simulated or the

controlled application of irregular, unusual or extreme conditions on the Total System or any part of the Total System, but which do not include

Commissioning or re-Commissioning tests or any other tests of a minor

nature.

DOC6.2 Scope


(a) Major Customers connected to the Distribution System where

DSP(s) considers it appropriate;

(b) Embedded Generating Plant with a capacity greater than

2MW, or according to CA/PPA between DSP and Generators.


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DOC6.3 Procedures

DOC6.3.1 If the System Test is proposed by DSP(s) or the User connected to the

Distribution System then the provisions of DOC6 shall apply.

DOC6.3.2 If the system test will or may have an effect on the Transmission System, then

the provision of the Saudi Arabian Grid Code shall apply.

DOC6.3.3 System Tests which have a minimal effect on the Distribution System or the

systems of others will not be subject to this procedure; minimal effect shall be

taken to mean variations in voltage, Frequency and waveform distortion of a

value not greater than those figures which are defined in the Distribution

Planning Code.

DOC6.3.4 When DSP(s) or a User intends to undertake a System Test which may have

significant effect on the System of others normally twelve months notice, or

as otherwise agreed by DSP(s), shall be given by the person proposing the

System Test (Test Proposer) to DSP(s) and to those Users who may be

affected by such a System Test.

DOC6.3.5 The proposal shall be in writing and shall contain details of the nature and

purpose of the proposed System Test and shall indicate the extent and situation

of the Plant or apparatus involved.

DOC6.3.6 If the information set out in the proposal notice is considered insufficient by

the recipient they shall contact the Test Proposer with a written request for

further information which shall be supplied as soon as reasonably practicable.

DSP(s) shall not be required to do anything under DOC6 until they are satisfied

with the details supplied in the proposal or pursuant to a request for further

information.

DOC6.3.7 If DSP(s) wishes to undertake a System Test, DSP(s) shall be deemed to have

received a proposal of that System Test.

DOC6.3.8 DSP(s) shall have overall co-ordination of the System Test, using the

information supplied to it under DOC6 and shall identify in its reasonable estimation, which Users other than the Test Proposer, may be affected by the

proposed System Test.

DOC6.3.9 Following receipt of the System Test proposal DSP(s) shall evaluate the impact

of the System Test and discuss the proposals with Users identified as being

affected.


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DOC6.3.10 Within one month of receiving the System Test proposal DSP(s) shall submit

a report to the Test Proposer which shall contain:

(a) proposals for carrying out the System Test (including the manner in

which it is to be monitored);

(b) an allocation of costs between the affected parties, (the general

principle being that the Test Proposer will bear the costs); and

(c) such other matters that DSP(s) consider appropriate; an outline of the

procedure to be followed and the proposed test schedule and advice of

any costs.

DOC6.3.11 the proposal report shall be submitted to all those who received a notice

under DOC6.3.4.

DOC6.3.12 If the proposal report (or a revised proposal report as agreed between DSP(s)

and the Test Proposer) is approved by all recipients, the System Test can

proceed.

DOC6.3.13 At least one month prior to the date of the proposed System Test, DSP(s)

shall submit to all recipients of the proposal notice a programme which in

DOC6 shall be called a Final Test Programme stating the switching sequence

and proposed timings, a list of those staff involved in carrying out the System

Test (including those responsible for site safety) and such other matters as

DSP(s) deem appropriate.

DOC6.3.14 The final test programme shall bind all recipients to act in accordance with

the provisions contained within the programme in relation to the proposed

System Test.

DOC6.3.15 At the conclusion of the System Test, the Test Proposer shall be responsible

for preparing a written report (the “Final Report”) of the System Test for

submission to DSP(s).

DOC6.3.16 The Final Report shall include a description of the Plant and/or apparatus

tested and of the System Test carried out, together with the results, conclusions

and recommendations.

DOC6.3.17 Results of tests shall be reported to relevant parties, taking into account confidentiality issues.

DOC6.3.18 all system test procedures shall comply with all applicable legislation.


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DOC7: Monitoring Testing and Investigation

DOC7.1 Introduction

DOC7.1.1 In order to discharge its responsibilities in respect of safe, secure and

economic operation of the Distribution System and in accordance with its

licence conditions DSP(s) shall organize and carry out monitoring, testing and

investigation on the effect of User’s electrical apparatus or electrical

installation on the Distribution System.

DOC7.2 Scope


(a) all Embedded Generators (b) all Customers who are connected to the Distribution System

DOC7.3 Procedures

DOC7.3.1 DSP(s) shall, from time to time, determine the need to test or monitor the

quality of supply at various points on the Distribution System.

DOC7.3.2 The requirements for specific testing and/or monitoring may be initiated by the receipt of specific complaints as to the quality of supply on the Distribution System.

DOC7.3.3 Where testing or monitoring is required at the Connection Point with a User

then DSP(s) shall advise the User involved and DSP(s) shall make available

the results of such tests to the User.

DOC7.3.4 Where a User is found to be operating outside the technical limits specified in

the Distribution Code then the User shall rectify the situation or disconnect the

apparatus causing the problem from its electrical system connected to the

Distribution System immediately or within such time as agreed with DSP(s).

DOC7.3.5 Continued failure to rectify the situation shall result in the User being

disconnected.

DOC7.3.6 DSP(s) shall, from time to time, monitor the effects of the User on the


DOC7.3.7 The monitoring shall normally be related to the amount of Active Power and

Reactive Power or Flicker or Harmonics transferred across the Connection

Point.

DOC7.3.8 Where the User is exporting or importing Active Power or Reactive Power in


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an amount causing disturbances, DSP(s) shall inform the User and the User

shall restrict the power transfer to within the specified parameters.

DOC7.3.9 DSP(s) may check from time to time that Users are in compliance with

agreed Protection requirements and Protection settings.

DOC8: SAFETY CO-ORDINATION

DOC8.1 Introduction

DOC8.1.1 DOC8 specifies the safety rules and procedures to be applied by the DSP(s) to meet statutory requirements and Distribution License conditions and obligations.

DOC8.1.2 Similar safety rules and procedures shall be provided by other Users of the

Distribution System when carrying out work or tests at the operational

interface with the DSP(s).

DOC8.2 Objectives

DOC8.2.1 The objectives of safety co-ordination procedures are to lay down the Safety Management criteria to be applied, to ensure safety of persons working on the

Distribution System and/ or across operational and ownership boundaries.

DOC8.3 Scope

DOC8.3.1 DOC8 specifies the safety rules and procedures that apply to the DSP(s) and

the following Users of the Distribution System:

a) Embedded Generators

b) Major Customers

c) Any other party reasonably specified by the DSP(s) including Users connected

at Medium or Low Voltage for appropriate sections of DOC8 when necessary

d) Agents of the DSP(s) or Users working on the Distribution System or at or

across operational boundaries.

DOC8.4 Procedures

DOC8.4.1 The Safety Management principles and procedures (Safety Management

System) for ensuring the health and safety of all relevant personnel shall be

specified by DSP(s) and Users for work on their respective Systems or Plant

apparatus connected to them.

DOC8.4.2 There shall be joint agreement by DSP(s) and Users on which Safety

Management System is to be used for sites or locations where an operational


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boundary exists and proper documentation of the safety precautions to be

taken shall be maintained.

DOC8.4.3 There shall be written authorization of personnel who do the work of control,

operation, work or testing of Plant apparatus forming part of, or connected

to, the Distribution System.

DOC8.4.4 There shall be joint agreement between DSP(s) and Users which specifies

responsibility for system or control equipment which shall ensure that only

one party is responsible for any item of Plant or apparatus at any one time.

DOC8.4.5 DSP(s) and each User shall at all times have nominated a person or persons

responsible for the co-ordination of safety on the respective system.

DOC8.4.6 DSP(s) and each User shall maintain a suitable system of documentation

which records all relevant Operational Events that have taken place on the

Distribution System or other system connected to it and the co-ordination of

relevant safety precautions for work.

DOC8.4.7 System diagrams which show sufficient information for control personnel to

carry out their duties shall be exchanged between DSP(s) and User as required.

DOC8.5 Safety at the DSP(s) / User Interface

DOC8.5.1 The following procedures set down the basic safety requirements at the

operator and DSP(s) interfaces. These procedures are necessary to ensure the

safety of all who may have to work at either side of the interface or on the

interface (boundary).

(a) Written rules for safety working and communicating procedures shall

be available and used by all persons who may have to work at or use

the facilities provided at the Interface.

(b) Electrical equipment connected to either side of the interface and

interface equipment shall be under the control of a named person at

either side.

(c) Each item of equipment shall be controlled by only one identifiable

person at any one time.

(d) Adequate means of isolation shall be provided at the interface to allow

work to be carried out safely at either side of the interface.

(e) Where necessary to prevent danger adequate facilities for Earthing

shall be provided at either side of the interface to allow work to be

carried out safely at the interface or at either side of the interface.


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(f) Adequate working space, adequate means of access and egress and,

where necessary, adequate lighting shall be provided at all electrical

equipment, on or near which work is being done in circumstances

which may cause danger.

(g) All electrical equipment shall be suitably identified where necessary

to prevent danger.

(h) Electrical installations and equipment shall comply with the relevant

statutory requirements.

DOC8.6 Safety Rules

DOC8.6.1 Operation and Maintenance of the User’s equipment shall only be carried out by authorized personnel. Before first Commissioning the Plant, operating procedures shall be agreed with the DSP(s).

DOC8.6.2 Instructions for operating and / or Earthing the User’s electrical equipment shall

be clearly displayed in the User’s Medium and High Voltage switch room.

DOC8.6.3 Safety Procedures for personnel working on or in close proximity to the

Distribution System Plant and apparatus shall be governed by the DSP(s).

DOC8.6.4 In the event of a conflict between the provisions of this Code and the

provisions of the TSP safety rules, the provisions of the TSP Safety Rules shall

take precedence.


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PART 6: GLOSSARY

DCD1 Active Power

The product of voltage and the in-phase component of alternating current (normally measured in kilowatts (kW) or megawatts (MW)).

DCD2 Ambient Temperature

The surrounding temperature (in the absence of the equipment) of the

immediate environment in which equipment is installed. This temperature

normally varies. A derived constant value is taken for the purposes of designing

or rating equipment.

DCD3 Apparent Power

The vector addition of Active Power and Reactive Power measured in units of

VA, kVA and MVAr

DCD4 Asynchronous

Refers to generating Plant and electric drives, and has the meaning that the

Plant or drive is not linked to the System Frequency by a Synchronising torque.

In general, this means that there is no natural contribution to the inertia of the Total System, although control mechanisms may be employed to synthesise a

contribution which assists in stabilising the Total System after a disturbance.

DCD5 AVR

Automatic Voltage Regulator

DCD6 Back-Up Protection

That Protection system which will open a Circuit Breaker or other fault-

current interrupting device in the absence of the current Protection operation

of another Protection system

DCD7 Black Start

The procedure which is necessary for recovery from a total or partial system

shutdown

DCD8 Bulk Supply Point

A point of connection between the Transmission System and the Distribution

System or between the Transmission System and a directly connected

Customer

DCD9 Central Dispatch

The Dispatch of Generating Units by the Transmission Service Provider

(TSP), and Centrally Dispatchable shall be construed accordingly

DCD10 Centrally Dispatched Generating Units Generating Units subject to Dispatch by the TSP

DCD11 Circuit Breaker

A mechanical switching device, capable of making, carrying and breaking


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currents under normal circuit conditions and also of making, carrying for a

specified time and breaking currents under specified abnormal circuit

conditions, such as those of short circuit

DCD12 CHP - Combined Heat and Power

The simultaneous production of utilizable heat and electricity from an

integrated thermo-dynamic process

DCD13 Commissioning

The final process of testing part of a system prior to that part of the system

being considered suitable for normal use

DCD14 Connected Load

The sum of the nameplate ratings of all present and future electrical equipment

installed by a Customer. Connected load is measured in volt-amperes (VA).

DCD15 Connection Agreement

An agreement between DSP(s) and each User setting out terms relating to a

connection with the Distribution System

DCD16 Connection Point

The physical point at which User’s Plant or apparatus is joined to the


DCD17 Customer

A User whose premises are connected to the Distribution System for the purpose of obtaining a supply of electricity at that premises

DCD18 Customer with Auto-Production

A Customer generating electricity for their own use.

DCD19 Deadband

In relation to a control system is that range of a controlled parameter over

which the control system remains inactive.

DCD20 Delta Regulation

Refers to a control system applied to a Renewable Resource Generating Unit

whereby the Generating Unit continually operates at a settable fixed fraction

below its instantaneous maximum Output so as to have energy available to

assist in Frequency control of the Total System.

DCD21 Demand

The electric power which is drawn for the system by a Customer, usually

expressed in MW, MVA or MVAR.

DCD122 Demand Load

The maximum load drawn from the power system by a Customer at the


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Customer’s interface (either estimated or measured).

DCD123 Dis-connector

A device which provides in the open position a means of disconnecting

apparatus from the Distribution System in accordance with specified requirements

DCD24 Dispatch

The issue of instructions for Generating Units to achieve specific Active Power and Reactive Power outputs within Registered Data parameters and by stated times.

DCD25 Distribution Code

This code, required to be prepared by DSP(s) pursuant to condition 14

(Compliance with transmission, distribution and market codes) of he

Distribution Licence and approved by ECRA as revised from time to time

with the approval of, or by the direction of, ECRA.

DCD26 Distribution Code Review Panel

The panel with the functions which are set out in DGC6.

DCD27 Distribution License

A distribution license granted under Article 5 and 6 of the Electricity Law

promulgated on 20/10/1427 AH (21/11/2006 AD) by Royal Decree M/56

and ECRA Charter dated 17/05/1425 AH (05/07/2004 AD).

DCD28 Distribution System

The system which consists of electric lines, electric Plant, transformers and

switchgear and which is used for conveying electricity to final Customers.

DCD29 Distribution Service Provider (DSP)

The legal entity that is licensed to own and maintain a network on the Distribution System (or has such right by virtue of its historic existence for this purpose).

DCD30 Distribution Use of System Agreement

The agreement between DSP(s) and Retailers/ Traders for transport of

electricity from the Transmission System or Embedded Generators through

the Distribution System to Customers.

DCD31 Disturbing Loads

Loads which have the potential to introduce waveform distortion (Harmonics,

Flicker) or phase unbalance into the system.

DCD32 Droop


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In relation to the operation of the governor of a Generating Unit, the

percentage drop in Saudi System Frequency which would cause the

Generating Unit under free governor action to change its output from zero to

full load.

DCD33 Earthing

The provision of a connection between conductors and earth by means of an

Earthing Device.

DCD34 Earthing Device

A means of providing a connection between a conductor and earth of adequate

strength and capability for its intended purpose.

DCD35 ECRA Electricity and Co-Generation regulatory Authority.

DCD36 Effectively Earthed System

A power system in which the neutral is connected to earth either directly or through a neutral resistor.

DCD37 Embedded

Having a direct electrical connection to the Distribution System.

DCD38 Event An unscheduled or unplanned (although it may be anticipated) occurrence on or relating to a System including, without limiting that general description, faults, incidents and breakdowns.

DCD39 Event Recorder A certified device that measures and records data at locations on the Saudi System

DCD40 Fault Level

Prospective current that would flow into a short circuit at a stated point on the

System. It is expressed in kA or in MVA.

DCD41 Final Connection Certificate

Is a document issued by the DSP to a User indicating that the User’s

installation is Distribution Code compliant, or is compliant with the

Distribution Code as derogated.

DCD42 Flicker Periodic fluctuations in voltage, at frequencies below the fundamental Frequency. These are generally expressed as percentage variations, relative to the fundamental voltage.

DCD43 Frequency

The rate of oscillation of the AC supply. This is generally expressed as a


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Frequency range, in terms of a nominal Frequency in Hz (cycles per second),

with plus and minus percentage limits.

DCD44 Frequency Control

The control of the Frequency on the Total System

DCD45 Frequency Response

The automatic adjustment of Active Power output from a Generation Unit(s) in response to Frequency changes.

DCD46 Frequency Sensitive Mode

The operation of a Generating Unit whereby its generation level is varied automatically to compensate for variations in the Frequency of the System

DCD47 Fundamental Frequency

The operating or system Frequency of the Power System. Parameters whose

Frequency is the same as the fundamental Frequency are referred to as

fundamental parameters.

DCD48 Generating Plant

A power station with one or more Generating Units.

DCD49 Generating Unit An electrical generator and its associated prime mover, together with all associated Plant and apparatus and any generator transformer, which relate exclusively to the operation of that generator, which in the case of:

a steam turbine will include the boiler and heat exchanger and in addition in the case of a solar concentrator the solar collectors, a gas turbine will include the gas generator/combustion turbine, and a fuel engine will include the engine any gearbox and the prime

mover. In the case of:

wind generation: a wind turbine Generating Unit comprises one or more wind turbine generators that are controlled together, including all Plant and apparatus and any step-up transformer which relates exclusively to the operation of those wind turbine generators. solar generation: a solar Generating Unit is a group of devices which are controlled together to collect or concentrate the sun’s rays within a solar power production facility, together with all Plant and apparatus and any step-up transformer which relates exclusively to the operation of that part of the solar power production Facility.

Generating Units could be Synchronous or Asynchronous.

DCD50 Good Industry Practice

The standard of practice attained by exercising that degree of skill, diligence,

prudence and foresight which would reasonably and ordinarily be expected

from a skilled and experienced operator engaged in the same type of


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undertaking under the same or similar circumstances.

DCD51 Grid Code

The Saudi Arabian Grid Code

DCD52 Harmonics

Sinusoidal currents with a Frequency equal to an integer multiple of the

fundamental Frequency.

DCD53 High Voltage

A voltage, used for the supply of electricity, the lower limit of nominal RMS

value of which is greater than 100kV.

DCD54 IEC

International Electrotechnical Commission.

DCD55 Isolated

Disconnected from associated equipment by an isolator or adequate physical separation.

DCD56 kVA

Kilo-Volt ampere.

DCD57 Limited Performance Certificate

Is a document issued by the DSP to a User indicating that the User’s installation is Distribution Code compliant (or is compliant with the Distribution Code as derogated) except for certain matters which have were previously but are no longer compliant. For the avoidance of doubt, such a certificate can only be issued were the Plant is deemed safe for operation

DCD58 Low Voltage

A voltage used for the supply of electricity, the upper limit of nominal RMS

value of which does not exceed 1kV.

DCD59 Major Customer

A Customer who is supplied at Medium Voltage whose Load is greater than

1MVA

DCD60 Medium Voltage

A voltage used for the supply of electricity, the nominal value of which is between 11kV and 69kV.

DCD61 Normal Operating Frequency

The Frequency at which the system normally operates i.e. 60Hz.


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DCD62 Operation A scheduled or planned action carried out on a system.

DCD63 Operational Effect

The effect of any Operation which causes the Transmission System or the

Distribution System, or the system of other Users, to operate (or be at a

materially increased risk of operating) differently from the way in which they

would or may have operated in the absence of such Operation.

DCD64 Output

As the context requires, the Active Power delivered in MW, the Reactive

Power delivered or absorbed in MVAr or the Apparent Power in MVA of a

Generating Unit, measured by certified meters at the Connection Point or

measured at some other point and adjusted by adjustment factors.

DCD65 Planned Outage

An outage of Generating Plant or of part of the Transmission System or of part

of the Distribution System other than a forced outage.

DCD66 Plant

Fixed and movable items used in the generation and/or supply and/or transmission and/or distribution of electricity other than apparatus.

DCD67 Power Factor

The ratio of Active Power to apparent power.

DCD68 Power Park Module

An Asynchronous Renewable Energy Generating Unit which, for the

avoidance of doubt, is based upon a single device or group of devices

generating electricity, which:

are connected to the network Asynchronously or through power

electronics,

has a single Connection Point to the Distribution System, and

is/are controlled to behave as one Generating Unit.

DCD69 Power Producer

The person who generates electricity

DCD70 Protection

The provisions for detecting abnormal conditions in a System and initiating

fault clearance or actuating signals or indications.

DCD71 Reactive Power

The product of voltage and current and the sine of the phase angle between

them which is normally measured in Kilo vars (kVAR) or Mega vars


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(MVAR).

DCD72 Registered Capacity

Refers to a Generating Unit and is the normal full Load capacity of that

Generating Unit in MW measured at the Connection Point and set down in the

Connection Agreement having regard to Reactive Power or Power Factor

requirements under this Distribution Code.

DCD73 Renewable Resource

Refers to energy sources deemed to cause no or low carbon emissions and

includes solar, wind, geothermal and energy from waste. Hybrid technologies

are assessed as renewable when operating solely on renewable resources.

DCD74 Retail Business The business of bulk purchase for the purpose of retail sale of electricity to Consumers or large consumers authorized by a license.

DCD75 Safety Management

The procedure adopted by the DSP or a User to ensure the safe operation of

its system and the safety of personnel required to work on that system.

DCD76 Safety Procedures

The procedures which are specified within a Safety Management system.

DCD77 Significant Incident

An Event which has had or which may have an Operational Effect on the

Transmission or Distribution system or on a User’s installation.

DCD78 Stand-by

In relation to an electricity generator, means a Plant which is not connected in

such a way as to be Synchronised with the Total System. Such a generator is

not to be operated in parallel with the Total System and, for the avoidance of

doubt, is not a Generating Unit within the meaning of the Distribution Code.

DCD79 Step Change in Voltage

A step change is defined as a single, rapid change of the RMS voltage.

Distribution System voltage step changes can occur due to switching in and

out of capacitors, lines, cables, transformers and other Plant.

DCD80 Synchonise

The condition where a Generating Unit, or a System, is connected to the

busbars of another system or the Total System, so that the Frequencies and

phase relationships of that Generating Unit or System are identical (within

operational tolerances) to those of the other system or the Total System


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DCD81 Synchronous

Refers to a Generating Unit or drive and has the meaning that the Plant or

drive is linked to the System Frequency by a Synchronising torque. In general,

this means that there is a natural contribution to the inertia of the Total System,

which assists in stabilising the Total System after a disturbance.

DCD82 System Tests

Those tests which involve simulating conditions or the controlled application

of irregular, unusual or extreme conditions on the Total System or any part

of it, but not including routine testing, Commissioning or re-commissioning tests.

DCD83 Temporary Connection Certificate

Is a document issued by the DSP to a User indicating that the User’s installation is Distribution Code compliant (or is compliant with the

Distribution Code as derogated) except for certain matters which have not

yet been tested.

The matters to be demonstrated and the period of validity of the Temporary Compliance Certificate are stated in the certificate together with the

consequences of:

insufficient System conditions to determine compliance within the

validity period of the certificate; and

inadequate performance of the Plant under actual System conditions.

.

DCD84 Total Harmonic Distortion

Total harmonic distortion is the aggregate of the harmonic distortions at all

harmonic frequencies. This is expressed as the root mean square value of

harmonic distortions, at all harmonic frequencies.

DCD85 Total System

The Distribution System together with its connected Customer

installations in Saudi Arabia or part thereof (as the context requires)

and including (as the context requires) the effects of connection to

the Transmission System.

DCD86 Trading Business

The business of bulk purchase for the purpose of sale of electricity from/ to

other Licensees or large Consumers authorized by a license.

DCD87 Transmission System

Reference shall be made to the Saudi Arabian Grid Code (SAGC) for detailed

definition.

DCD88 Transmission Service Provider (TSP)

The legal entity that is licensed to own and maintain a network on the Transmission System (or has such right by virtue of its historic existence for


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this purpose).

DCD89 User

A term used in various sections of the Distribution Code to refer to the persons using the Distribution System, more particularly identified in each section of the Distribution Code.

DCD90 Voltage

Electrical pressure

DCD91 Voltage Control

The retention of the voltage on the System within acceptable limits

DCD92 Voltage Reduction

A method to control Demand temporarily by reduction of system voltage.

DCD93 Voltage Unbalance

In three-phase networks, the conditions in which the RMS values of the phase voltages, or the angles between consecutive phases, are not equal.

DCD94 Zero Phase Sequence

A set of phases of equal magnitude and zero phase angle, relative to each

other. The 3-phase values are thus in phase with each other. The term zero

sequence may be applied, in the same sense, to AC voltages and currents.


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SECURITY

AND PLANNING STANDARDS

FOR THE DISTRIBUTION SYSTEM (Demand Customers Only)


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CONTENTS 1.0 INTRODUCTION

1.1 General 93

1.2 Definition 93

1.3 Aim of Planning 95

2.0 DISTRIBUTION SYSTEM 96

2.1 Standard Configuration 96

2.2 Voltage Levels 97

2.3 Effects of Disturbing Loads 97

3.0 ASSESSMENT OF NEW LOAD 98

3.1 Application Form 98

3.2 Information Required from Customers 98

3.3 Need for room substation 99


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INTRODUCTION

1.1 General

The DSP(s) is required to operate and ensure the maintenance of and develop, as

necessary, a safe, secure, reliable, economical and efficient electricity


To this end, this document, “Security and Planning Standards for the Distribution System” has been prepared in accordance with the Distribution Code.

It outlines DSP(s)‟s approach to the development of the network, giving details of

how the connection of new loads and Embedded Generators to the Distribution

System are assessed. It is intended as a guide to Users of the Distribution System.

While this guide refers to Customer’s loads, the same factors will apply, in general,

to Generators also. There are however, some specific requirements relating to

Generators and these are included under a separate heading (part- 4).

1.2 Definitions

In general the terms used in this document have the meanings intended in the

Distribution Code. As a brief guide, the terms used in this document are defined below:

Term Definition

Connection

Asset

The network erected to connect the Connection Point

to the existing Distribution System. The connection

asset forms part of the Distribution System and is not

shared by other Users.

Continuity or

Continuity of

Supply

This describes the quality of a supply as it relates to

outages, whether caused by faults or planned work.

A set of measures are required to describe continuity

but, in general, the lower the incidence of outages

and the shorter their duration, the higher the

continuity.

Distribution System The electric lines, Plant and switch-gear used to

convey electricity to final Customers (excluding

Customers connected directly to the Transmission

System (grid)).

Disturbing Load An electrical load that of its nature may affect the


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quality of electricity supply of other Customers.

Examples are welders, large electric motors etc.

Flicker

Voltage fluctuations, caused by a disturbing load

(or rapid variations in Generator output), the major

effect of which is Flickering of standard

(incandescent) light bulbs.

Looped Connection

As described in DPS

Losses

Electrical losses are the difference between the

energy entering the Distribution System and that

delivered to Customers. Losses are the energy lost

in the network due to the heating effect of the

electricity passing through it.

Maximum Import

Capacity

This is the maximum load that the Customer has

contracted with DSP(s).

Normal Feeding

The network configuration under normal

conditions and when all distribution Plant is in

service. The normal feeding arrangement is

typically designed to provide best voltage

performance, to minimize network losses and to

make optimum use of the capacity of feeding

substations.

Security of Connection

The expectation that the Connection Point will

remain energized.

Short Circuit Level

The short circuit level is a measure of the

“strength” of the network i.e. the ability to limit the

impact of Disturbing Loads and to maintain

voltage stability. The size of the Customer

switched load relative to the short circuit level

determines the magnitude of its impact on the

voltage.

Short Circuit Rating

This refers to the short circuit rating of the item of

Plant concerned.


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Standby Feeding The feeding arrangement when one or more items

of network Plant is out of service. The exact feeding

arrangement will depend on which items are out of

service. As standby feeding is a temporary

arrangement, different standards of voltage apply.

Bulk Customer

substation

A standard structure owned and operated by

substation DSP(s) containing the distribution

equipment necessary to connect a Customer to the

Distribution System. Terminal substations are

operated at the connection voltage of the Customer

i.e. transformation is not required.

Distribution

substation

A standard structure owned and operated by

Substation DSP(s) containing one or more

transformers, to convert electricity at one standard

distribution voltage to a lower standard voltage.

1.3 Aim of Planning

The aim of planning is to ensure that the Distribution System is developed in an

orderly and cost effective manner. It is necessary to ensure that there is capacity

available to meet new loads as they arise, and to meet ongoing growth

requirements. It is also necessary to ensure that new connections are made:

1. in an economic fashion

2. with a view to the possible future needs of the Customer and the network 3. in a way that is technically acceptable

In general the MV networks are planned to a single contingency standard. This

means that the system is designed to withstand a single contingency, and any

outages experienced for this single contingency are only for such time as is

required to transfer load from faulted Plant. In summary, DSP(s) will provide

Customer connections which will deliver the required capacity to an acceptable

standard as detailed in the Distribution Code and will comply with the Saudi

Arabian Grid Code (SAGC) at all points of connection to the Transmission System.

A higher standard of installation or a higher security of connection arrangement

can be provided at the Customer’s request, with the provision that any additional

costs will be attributed in full to the Customer.


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2.0 DISTRIBUTION SYSTEM

2.1 Standard Configuration


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2.2 Voltage Levels

There are a number of standard voltages in use on the Distribution System and

Customers will be connected at one of these levels. Voltage Levels at which a

connection can be provided are as follows:

Voltage Level

Nominal Voltage

Low

Voltage

(LV)

220/127V (phase-phase/phase-

neutral)


neutral)


neutral)

Medium

Voltage

(MV)

13.8kV, 33kV , 69kv(standard)

11kV, 34.5kV (existing but non-

standard)

Table 1: Distribution System Nominal Voltages

2.3 Effects of Disturbing Loads

Certain types of equipment such as motors and welders may cause

fluctuations in the supply voltage which cause disturbances to the

connection of other Customers. Where Customers intend to install any

equipment likely to cause supply disturbances, this equipment must be

evaluated to assess the likely impact. The limits imposed on Disturbing

Loads are specified in the Distribution Code. It may be necessary,

depending on the characteristics of the equipment, for a Customer

connection to be made using a different network configuration via a

higher voltage, a dedicated substation or other method.


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3.0 ASSESSMENT OF NEW LOAD

3.1 Application Form

The assessment of the connection for a new load requires details of the

load. The details should be provided by completing an application form.

3.2 Information Required from Customers

Details of the information required from Demand Customers and

Generators seeking connections or extensions to the Distribution System

are provided in the Distribution Code. Application forms for connection

are available from DSP(s) offices, and are on the DSP(s)‟s website.

Specifically the following information may be requested, depending on

the nature of the load:

3.2.1 Geographical Location

Site location maps and site layout plans in order to determine the location

of the proposed load in relation to the existing network and plan cover

area

3.2.2 Maximum Import Capacity (MIC)

Maximum Import Capacity (MIC) required, the size and nature of the

load, diversity of the load and proposed phasing of the development i.e.

the pace at which the load is expected to increase from a specified initial

Demand to the full Demand.

3.2.3 Disturbing Loads

Details of any disturbing elements of the load are required such as:

Large motors - details of starting arrangements for all large motors. Disturbing Loads i.e. electric welding, and details of the nature and

usage pattern of the disturbing load.

Harmonics - details of any non-linear equipment likely to produce

Harmonics on our system and any filtering arrangements which the

Customer may have already in place. The Customer should also

provide details of compensation or balancing equipment connected. Unbalanced Loads - Where a Customer has a three phase supply, load

should be balanced as evenly as possible over the three phases.

The above is an example of the information which may be requested.

Depending of the size and complexity of the load, additional information

may also be requested.

Power Factor - The Power Factor of the Customers load as seen by the


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network must be 0.85 or higher. No Customer may present a leading

Power Factor load to the DSP(s) system.

3.2.4 Multiple Customer Development Versus Single Load Whether the

application is for infrastructure to facilitate connections to multiple end

Customers within a development or is for connection of a single

Customer.

3.2.5 Specific Requirements

Details of any specific Customer requirements for connection of the load.

3.2.6 Load Coincidence

Customers should note when assessing the Capacity requirements that

not all of the equipment will be operating at full load at the same time.

The Customer should apply a coincidence factor to each component of

the load, as well as to the overall load in order to assess the capacity

required. Coincidence factors will vary depending on the nature of the

load.

3.3 Need for room substation

As per DSP(s) Customer service manual.

Documents

The Saudi Arabian Distribution Code...The Saudi Arabian Distribution Code Page 3 of 99 10 DCRP-2011-010 12-10-2011 Clause 1.3(g), the word “new” deleted from the definition of