The Saudi Arabian Distribution Code
Updated Version: April 2021
Table of Contents
TABLE OF CONTENTS
The Saudi Arabian Distribution Code
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Table of Contents
The Saudi Arabian Distribution Code
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Table of Contents
The Saudi Arabian Distribution Code
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Table of Contents
The Saudi Arabian Distribution Code
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Table of Contents
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Table of Contents
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Appendices
APPENDICES
The Saudi Arabian Distribution Code
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Foreword
FOREWORD
This Forward to the Distribution Code is provided to Users and to
prospective Users of the Distribution System for their information only and
does not constitute a part of the Distribution Code.
This Distribution Code sets out the requirements of Users and the
distribution company(s) for connecting to the Distribution System and for
planning and operational purposes and covers both normal and
exceptional circumstances. It is however, a live working document and,
from time to time, is subject to revision to reflect the technical development
of the regulatory framework of the industry 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 GC.9. Upon receipt of such proposals for change,
the DCRP will carry out the necessary investigation and process to study
these proposals and officially prepare a report of recommendations to
WERA for its approval. The DCRP is an advisory body which represents
stakeholders having interests in the Distribution System and its
membership is outlined in chapter GC.9.2 of this 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 WERA’s web site www.wera.gov.sa.
The Saudi Arabian Distribution Code
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Preface
PREFACE
This Preface does not legally constitute part of the Distribution Code.
The 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 Distribution Service
Providers (DSP's) and system Users, owners of generation (i.e. Power
Producers) and Customers for accessing and using the Distribution
System, more specifically to:
define obligations, responsibilities, and accountabilities of all parties
for ensuring open, transparent, non-discriminatory, and economic
access and use of the system while maintaining its safe, reliable and
efficient Operation;
define minimum technical requirements; and
set out the information exchange obligations.
The Distribution Code is a comprehensive document and Users of the
Distribution Code may need to interact with it thus:
Other Persons Planning to Connect to the Distribution System
These persons are Users of the Distribution Code and should pay
particular attention to the Planning Code and Connection Conditions. The
Connection Conditions state the performance which Users Plant must
meet and all data required is stated in Tables appended to the Planning
Code. This is because that the data is required to either initially or on an
on-going basis plan the Distribution System and the User Connection.
There are duties in the Planning Code whereby the DSP must supply data
to the User to allow the User system to be planned.
Users Already Connected to the Distribution System
Persons already Connected, except as above, are Users of the
Distribution Code and are reminded that the Connection Conditions are
the technical requirements not just to be Connected but to remain
Connected. Such persons have duties under the Planning Code to report
changes or intended changes in the data and to report annually or when
they are aware of changes in load or generation levels or profiles.
Where specific dates are to be used for profiles to assist the TSP in overall
planning, the DSP has duties under the Planning Code to make these
known.
Ongoing Obligations of All Users
Users owning generation or storage greater than 200kW in size or Users
Connected at MV, should be aware that they will have duties to interface
annually and on an on-going basis with the DSP under the Operating
Code. The annual information is to assist the DSP to plan outages and
maintenance and the on-going duties help the DSP to manage the safe,
economic and efficient day-to-day running of the system by understanding
the expected flows on the network. There are also investigative and
reporting duties falling on Users and the DSP if certain Events occur which
The Saudi Arabian Distribution Code
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Preface
might create damage. The safety interface between Users and the DSP is
controlled underOC.8.
All Users and Customers in Respect of Metering
Any User will need to refer to the Metering Code to determine their
obligations etc. in relation to metering for settlements purposes.
DSPs have duties under the Distribution Code to design and operate the
Distribution System within the limits stated in the Planning Code. In
addition to the duties mentioned above, DSPs have duties to Users related
to implementing safety procedures at the interface with Users’ systems,
and to advising Users about load shedding.
The Saudi Arabian Distribution Code
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List of Abbreviations
LIST OF ABBREVIATIONS
Abbreviation
Meaning
A
Ampere and the combining form for ampere
AC
Alternating Current
AVR
Automatic Voltage Regulator
BIL
Basic Insulation Level
CC
Connection Conditions
CHP
Combined Heat and Power
COSEM
Companion Specification for Energy Metering
DC
Direct Current
DCRP
Distribution Code Review Panel
DLMS
Distribution Line Message Specification
DSP
Distribution Service Provider
ESPM
Electricity Service Provision Manual
GC
General Conditions
Hz
Hertz
IEC
International Electrotechnical Commission
IEEE
Institute of Electrical and Electronics Engineers
kA
Kiloampere
kV
Kilovolt
kVA
Kilovolt ampere
kVAr
Kilovolt ampere reactive
kW
Kilowatt
kWh
Kilowatt hour
LV
Low Voltage
MC
Metering Code
min
Minute
MIN
Meter Identification Number
MRS
Metering Registration System
ms
Millisecond
MV
Medium Voltage
MVA
Megavolt ampere
MVAr
Megavolt ampere reactive
The Saudi Arabian Distribution Code
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List of Abbreviations
Abbreviation
Meaning
MW
Megawatt
OC
Operating Code
OIML
Orgainsation Internationale de Metrologie Legale
PC
Planning Code
PV
Photovoltaic
RISSP
Record of Inter-System Safety Precautions
RMS
Root mean square
RMU
Ring Main Unit
s
Second
SADC
Saudi Arabian Distribution Code
SAGC
Saudi Arabian Grid Code
SASO
The Saudi Standards, Metrology and Quality Organization
SCADA
Supervisory Control and Data Acquisition
SF6
Sulphur Hexaflouride
SSECC
Saudi Sustainable Energy Control Center
TSP
Transmission Service Provider
V
Voltage
VA
Volt ampere
VAr
Volt ampere reactive
W
Watt
WERA
Water and Electricity Regulatory Authority
X/R
Reactance over resistance
The Saudi Arabian Distribution Code
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Definitions
DEFINITIONS
Name
Definition
Active Power
The product of Voltage and the in-phase component of alternating current
(normally measured in W, kW or MW).
Apparent Power
The vector sum of Active Power and Reactive Power expressed in VA, kVA
or MVA.
Asynchronous
A Generating Unit or electric drive, and has the meaning that the
Generating Unit 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.
Asynchronously shall be construed accordingly.
Asynchronous
Generating Unit
A Generating Unit which, 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.
An Asynchronous Generating Unit is comprised of all the Asynchronous
generating and Energy Storage devices in the User’s installation which are
capable of being operated as a single Generating Unit.
Backup
Protection
A Protection system which will supplement the main Protection by opening
a Circuit Breaker or other fault-current interrupting device in case the latter
should be ineffective, or to deal with faults in those parts of the power system
which are not readily included in the operating zones of the main Protection.
Black Start
The procedure, for recovery from a total or partial system shutdown.
Bulk Supply
Point
A Connection Point between the Transmission System and the
Distribution System or between the Transmission System and a directly
Connected Customer of the Transmission System.
Central
Dispatch
The Dispatch of Generating Units by the Transmission Service Provider.
Centrally Dispatchable and Centrally Dispatched shall be construed
accordingly.
Chairperson
Means the person who chairs the Distribution Code Review Panel with the
duties and responsibilities set out the General Conditions.
Circuit Breaker
A mechanical switching device, capable of making, carrying and breaking
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.
Commissioning
Tests
Are tests carried out to prove that part of a system or Plant or apparatus is
compliant with its specification and is suitable for normal use.
Committed
Project
Planning Data
The data (as further specified in the Planning Code) relating to a prospective
User
Competent
Persons
Persons with sufficient technical knowledge and/or experience to avoid
danger, authorised under a Safety Management regime to carry out defined
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Definitions
Name
Definition
duties to ensure safety from the Distribution System or the User’s system,
which duties include receiving, transferring and clearing specified safety
documents.
Complex
Refers to the arrangements at a Connection site with a User. If there is any
part of a User’s Connection equipment which can be energised from more
than one source of supply the installation is deemed Complex irrespective of
whether the Connection is at LV or MV.
Connected
Planning Data
The estimated values assumed for planning purposes by the DSP when
confirmed or replaced by validated actual data (as further specified in the
Planning Code).
Connection
In relation to any User’s installation or premises, the presence of a physical
Connection between that installation or premise and the Distribution
System;
Connect and Connected shall be construed accordingly.
Connection
Agreement
An agreement between a DSP and a User setting out terms relating to a
Connection with the Distribution System.
Connection
Conditions
Is the chapter of this Distribution Code, which sets out for Users, and
prospective Users, the technical requirements to be and remain Connected
to the Distribution System.
References to the Connection Conditions are prefixed CC.
Connection
Point
The physical point at which User’s Plant or apparatus is joined to the
Distribution System.
Controllable
Demand
Means the Demand which can be modulated in response to signals from the
DSP or other licensed organization to manage the Demand or flows on part
of or all of the Distribution System or the Total System.
Customer
A person whose premise is Connected to the Distribution System for the
purpose of obtaining a supply of electricity at that premises.
The size of Demand Customers Connected to the Distribution System
would normally not exceed to 25MVA.
Deadband
In relation to a control system is that range of a controlled parameter over
which the Output from that control system remains inactive.
Demand
The electric power which is drawn from the system by a Customer, usually
expressed in MW, MVA or MVAr.
Demand
Transfer
The process or capability of modifying the flows on the Distribution System
where the same total Demand can be supplied from more than one
Connection Point.
Detailed
Planning Data
or Detailed Data
Data additional to Standard Data needed to allow detailed stability studies to
be carried out.
Dispatch
The issue of instructions for Generating Units to achieve specific Active
Power and Reactive Power Outputs within registered data parameters or
declared availability and by stated times.
Dispatch
Instruction
Dispatch Instructions are instructions issued by the DSP to a User to alter
the operational state or mode of Operation of Plant, to Synchronise or desynchronise a Synchronous Generating Unit, to modify the amount of
Active Power (MW) or Reactive Power (MVAr) generated or consumed at
the User’s facility or to provide or change any other contracted system
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Definitions
Name
Definition
service.
Distribution
Capability
Statement
A statement produced annually for each distribution zone (including
Interconnected Systems and island systems): quantity of local and PV
generation, load growth for all types of Customers and Demand side
management, the distribution asset details including projects, Protection
system requirements, feeder automation, losses, Voltage regulation and
reliability.
Distribution
Code or Saudi
Arabian
Distribution
Code
means the SADC
Distribution
Code Review
Panel
The panel with the functions which are set out in GC9 of this Distribution
Code.
Distribution
Licence
A distribution licence 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
WERA Charter dated 17/05/1425 AH (05/07/2004 AD).
Distribution
Service
Provider
The legal entity that is licensed to own and maintain a network on the
Distribution System.
Distribution or
Distribution
System
The system which consists of electric lines, electric Plant, transformers and
switchgear and which is used for conveying electricity to final Customer.
Disturbing Load
Loads which have the potential to introduce waveform distortion (Harmonics,
Flicker) or phase unbalance into the system.
Droop
In relation to the Operation of the governor of a Generating Unit, the
percentage drop in Total System or Distribution System Frequency which
would cause the Generating Unit under free governor action to change its
Output from zero to full load.
Earth and
Earthing
The Connection of Plant or apparatus to Earth by an electrical conductor
either permanently or temporarily (e.g. to comply with Safety Rules during
work or testing).
Electricity
Service
Provision
Manual
A document prepared by the DSPs and approved by WERA which sets down
the procedures and arrangements for Minor Customer’Minor Customers
electricity Connections to the Distribution System. It is deemed to be
Distribution Code compliance. In the case of Minor Customer’s as outline
in the General Conditions of this Distribution Code.
Energy Exports
Energy Export mean the amount of active energy entering the Distribution
System from the User Connection Point.
Energy Imports
Energy Export mean the amount of active energy exiting the Distribution
System in to the User Connection Point.
Electric Vehicle
(EV) Charging
Station
An EV charging system or a set of EV charging systems enabling the charge
of Electric vehicles
Electric Vehicle
(EV) charging
System
Complete system including the EV supply equipment and the EV functions
that are required to supply electric energy to an EV for the purpose of
charging.
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Definitions
Name
Definition
EV DC Fast
Charger Station
An EV Charging Station with AC/DC built-in units. If AC/DC unit is enabled to
communicate with DSP, it can be a special type of Controllable Demand.
Electric Vehicle
(EV) supply
Equipment
Equipment or a combination of equipment, providing dedicated functions to
supply electric energy from a fixed electrical installation or supply network to
an EV for the purpose of charging.
Energy Storage
The conversion of electrical energy into a form of energy, which can be
stored, the storing of that energy, and the subsequent reconversion of that
energy back into electrical energy.
For the purposes of the Distribution Code it does not include storage of
energy from regenerative braking, from flywheel storage systems, or from any
storage source where the delivery of Active Power is fundamentally not
controllable or short lived, i.e. typically available for less than one minute. It
also excludes Synchronous compensation equipment.
Event
An unscheduled or unplanned (although it may be anticipated) occurrence on
or relating to the Distribution System including, without limiting that general
description, faults, incidents and breakdowns.
Event Recorder
A certified device that measures and records data at locations on the
Distribution System.
Fault Level
Prospective current that would flow into a short circuit at a stated point on the
Distribution System. It is expressed in kA or in MVA.
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.
Flicker
Periodic fluctuations in Voltage, at Frequencies below the fundamental
Frequency. These are generally expressed as percentage variations, relative
to the fundamentalVoltage.
Frequency or
Frequencies
The rate of oscillation of the AC supply. This is generally expressed as a
Frequency range, in terms of a nominal Frequency in Hz (cycles per
second), with plus and minus percentage limits. The nominal Frequency in
Saudi Arabia is 60Hz. The fundamental Frequency lies within the range of
nominal Frequency.
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
Distribution System.
Gas Zone
Diagram
A single line diagram showing boundaries of, and interfaces between, SF6
gas-insulated Plant modules which comprise part, or the whole, of a
substation at a Connection site, together with the associated stop valves and
SF6 gas monitors required for the safe Operation of the Distribution
System or the User’s system.
General
Conditions
Is the chapter of this Distribution Code, which sets out the overall scope of
the Code, the administrative arrangements including for suspension,
derogation and disputes and the mechanism for maintaining the Distribution
Code.
References to the General Conditions are prefixed GC.
Generating Unit
One or more devices converting energy into electricity, including any rotating
generation equipment, power electronic converters, prime movers and other
sources of energy, together with all associated apparatus and any generator
transformer, which relate exclusively to the Operation of that generator.
The Saudi Arabian Distribution Code
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Definitions
Name
Definition
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 combustion turbine and ancillary equipment,
and

a fuel engine will include the engine and any gearbox etc.
In the case of:

wind generation: a wind turbine Generating Unit comprises one or more
wind turbine generators that are controlled together, including all
apparatus and any step-up transformer and any reactive equipment 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.
In the case of Energy Storage

battery storage: the battery and its inverter/converter that are controlled
together to modulate the flow of Active Power and Reactive Power at
the Connection Point both when importing energy into the battery and in
the discharge of that energy.

compressed air storage: the means of using electricity to compress the
air, and the equipment driven by the compressed air to generate
electricity.
Any Energy Storage technology should be construed accordingly.
A Generating Unit can be a Synchronous Generating Unit or an
Asynchronous Generating Unit.
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
undertaking under the same or similar circumstances.
Grid Code or
Saudi Arabian
Grid Code
Means the SAGC.
Harmonics or
Harmonic
Sinusoidal currents with a Frequency equal to an integer multiple of the
fundamental Frequency.
Interconnected
System
Means the Distribution System when it is part of the Total System.
Isolation
The disconnection and separation of the electrical equipment from every
source of electrical energy in such a way that this disconnection and
separation is secure.
Licensed
Supplier
The legal entity that is licensed to supply energy to a User connected to the
Distribution System.
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.
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Definitions
Name
Definition
Low Voltage
A Voltage used for the supply of electricity, of nominal RMS value of which
does not exceed 1kV.
Major Customer
A User who is supplied at Medium Voltage whose load is greater than
1MVA.
Medium Voltage
A Voltage used for the supply of electricity, the nominal value of which is
11kV and greater than 1kV and up to 69kV
Member
Means a Member of the Distribution Code Review Panel
Meter or Meters
or Metering
Equipment
The Meter refers to the devise that measures the amount of energy flowing
through the Connection Point.
Meter Owner
Is the company or person responsible for installation, maintenance,
calibration and testing of the Meter and the Metering Equipment.
The Metering Equipment refers to any other associated equipment required
for the Meter to operate correctly.
In most cases the Meter Owner will be the DSP
Metering Code
Is the chapter of this Distribution Code which sets out the standards, tests
and arrangements for tariff metering employed on the Distribution System.
References to the Metering Code are prefixed MC.
The Metering Code excludes arrangements for the settlement system.
Minor Customer
A User Connected at LV with Demand less than 100kW and compliant with
the requirements of the Electricity Service Provision Manual.
A Minor Customer may have PV generation Connected at LV at the same
Connection Point with a Registered Capacity of less than 200kW and
compliant with the requirements of the Small Scale Solar PV Regulations.
Operating Code
Is the chapter of this Distribution Code which sets out for Users, and
prospective Users, the information and interactions with the DSP to enable
the DSP to efficiently plan and manage the day to day Operation of the
Distribution System References to the Operating Code are prefixed OC.
Operation
A scheduled or planned action carried out on the Distribution System.
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 it
(they) would or may have operated in the absence of such Operation.
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.
Ownership
Boundary and
Control
Boundary
A boundary established and which is referenced in a Connection
Agreement to determine the division of responsibility for assets (including
maintenance) and for their Operation between the DSP and a User. The
Ownership Boundary may differ from the Control Boundary and, if so, this
must be clear in the Connection Agreement.
Ownership Boundaries and Control Boundaries shall be construed
accordingly.
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
Planning Code
Is the chapter of this Distribution Code, which sets out the standards to
The Saudi Arabian Distribution Code
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Definitions
Name
Definition
which the Distribution System is planned, compels the DSP and Users to
exchange information prior to and after Connection and sets out the
fundamental process for obtaining or modifying a Connection to the
Distribution System. References to the Planning Code are prefixed PC.
Plant
Items used in the generation and/or supply and/or Transmission and/or
distribution of electricity.
Power Factor
The ratio of Active Power to Apparent Power.
Power Producer
The person who generates electricity. It includes any person who owns or
operates any Energy Storage device.
Preliminary
Project
Planning Data
Means the data relating to the proposed User development at the time a
User applies for a Connection but before an offer is made by the DSP and
accepted by the applicant User.
Protection
The provisions for detecting abnormal conditions in a system and initiating
fault clearance or actuating signals or indications.
Reactive Power
The product of Voltage and current and the sine of the phase angle between
them. Normally measured in kilovar (kVAr) or megavar (MVAr).
Registered
Capacity
Refers to a Generating Unit and is the normal full load capacity of that
Generating Unit set down in the Connection Agreement and stated in MW
measured at the Connection Point and under conditions of maximum
Reactive Power flows (or minimum Power Factor requirements) as required
in the Connection Agreement.
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.
Retailer
A person engaged in bulk purchase for the purpose of retail sale of electricity
to Users and authorized by a licence.
Safety
Coordinator
A person nominated by a User to be responsible for the coordination of safety
precautions at a Connection Point when work and/or testing is to be carried
out on a system which necessitates the provision of safety precautions on MV
Plant or on a Complex system.
Safety Coordination shall be construed accordingly.
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.
Safety Rules
The DSP document of the same name mandating the basic procedures for
work or testing on the Distribution System, or as described inOC.9, by its
staff when working on Users’ systems. The document forms part of the
Safety Management system employed by a DSP.
Security of
Supply
Standards and
Planning
Standards
This refers to standard approved by WERA and included as Appendix C to
this Distribution Code.
Significant
Incident
An Event which has had or which may have an Operational Effect on the
Transmission System or Distribution System or on a User’s installation.
Site Common
Drawings
Drawings that incorporate Connection site layout drawings, electrical layout
drawings, common Protection/control drawings and common services
The Saudi Arabian Distribution Code
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Definitions
Name
Definition
drawings prepared for each Connection site.
Site
Responsibility
Schedule
A schedule forming part of the Connection Agreement containing the
information and prepared in accordance with the Connection Conditions.
Standard
Planning Data
or Standard
Data
The general data required by the DSP under the Planning Code.
Synchronise
The condition where a Generating Unit, or a system, is Connected to the
busbar of another system or the Total System, so that the, Voltages,
Frequencies and phase relationships of that Generating Unit or system are
within operational tolerances to those of the other system or the Total
System.
Derivative words e.g. Synchronisation, Synchronising or Synchronised are to
be construed accordingly.
Synchronous
A Generating Unit or drive and has the meaning that the Generating Unit 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.
System Tests
or System Test
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 Tests or reCommissioning Tests.
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
Connection Certificate are stated in the certificate together with the
consequences of:

insufficient Distribution System conditions to determine compliance
within the validity period of the certificate; and
inadequate performance of the Plant under actual Distribution System
conditions.
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.
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.
Trader
A business authorised by a licence to bulk purchase electricity for the
purpose of sale from/ to other Licensees or large Customer.
Transmission
or
Transmission
System
Reference shall be made to the Saudi Arabian Grid Code for detailed
definition.
Transmission
The legal entity that is licensed to own and maintain a network on the
The Saudi Arabian Distribution Code
xiv
Definitions
Name
Definition
Service
Provider
Transmission System (or has such right by virtue of its historic existence for
this purpose).
User
The term applied to persons who are Connected to the Distribution System
and the requirements of this Distribution Code apply.
Voltage
Means the electrical pressure measured in volts or kilovolts.
The Saudi Arabian Distribution Code
xv
Introduction
INTRODUCTION
Purpose of the Distribution Code
This 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 fulfil 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.
The Saudi Arabian Distribution Code
xvi
1st Electronic Update as of October 2020
Introduction
Centrally dispatched generation
The Grid Code
Transmission Service Provider
Transmission System
Transmission connected customers
Planning
National Control Centre
Suppliers
Distribution Service Providers (DSP(s))
Information & Emergency management
Isolated generating units
Synchronous generating units
Asynchronous generating units
Distribution system planning &
connection
Customers (excluding small scale and
residential)
Distribution System
Retailers & traders
Minor customers
Figure 1. Grid Code and Distribution Code Boundaries
The Saudi Arabian Distribution Code
The Distribution Code
Distribution Service Provider
Distribution Control
17
ESPM
Introduction
Structure of Distribution Code
This Distribution Code is in six parts, as follows:
Introduction
This outlines the purpose of this Distribution Code, its relationship with
the Saudi Arabian Grid Code (SAGC) and how the various parts of the
Distribution Code are relevant to the different Users of the
Distribution System.
CHAPTER 1 General Conditions
This presents provisions, which are of general application to all parts of
the Distribution Code or facilitate the overall understanding of the
Distribution Code.
CHAPTER 2 Planning Code
This specifies the technical and design criteria and the basic procedures to
be employed in the planning and development of the Distribution
System.
CHAPTER 3 Connection Conditions
These define the minimum standards for equipment Connected or to be
Connected to the Distribution System and the performance required
from Users’ Plant.
CHAPTER 4 Operating Code
This part addresses various operational issues including load forecasting,
planning outages, reporting of operational changes and Events, safety
matters, procedures for dealing with emergencies and for dispatching
certain Users’ Plant.
CHAPTER 5 Metering Code
This Chapter of the Code sets out the requirements for all points of
Connection to the Distribution System to have a Meter of a prescribed
standard for the purpose of recording the volume of energy imported and /
or exported to the Distribution System.
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General Conditions
GENERAL CONDITIONS
CONTENTS
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19
General Conditions
INTRODUCTION
While each part of the Distribution Code presents the rules and
provisions relating specifically to that part, the General Conditions (GC)
presents provisions which are of general application to all parts of the
Distribution Code.
OBJECTIVE
The objectives of the General Conditions are as follows:
to ensure, insofar as it is possible, that the various sections of the
Distribution Code work together for the benefit of all Users; and
to provide a set of principles governing the status and development
of the Distribution Code and related issues as approved by WERA.
SCOPE
Scope of the General Conditions
The General Conditions apply to all DSPs and Users of the Distribution
System.
Scope of the entire Saudi Arabia Distribution Code
These General Conditions provides rights to all Distribution System
Customers to be treated equitably and obtain information regarding
Controllable Demand and the Metering Code) The technical
requirements placed upon Users of the Distribution Code (as amended
from time to time) shall be similarly enacted by the ESPM.
Minor Customer’Minor Customers are exempt from abiding by the data
exchange within the Connection Conditions, however Minor
Customer’Minor Customers are obligated to abide by the requirements of
the ESPM.
In the event of conflict between the two documents, the Distribution
Code shall prevail.
It shall be the duty of the Chairperson of DCRP to ensure that such
approved amendments are advised to parties responsible for the ESPM in
a timely manner.
HIERARCHY, IMPLEMENTATION AND ACCESS
The Distribution Service Provider licence imposes a duty upon DSP(s)
to implement and enforce the Distribution Code.
In the event of any conflict between the provisions of any direction of
WERA and the provisions of the Distribution Code, the provisions of
WERA’s direction shall prevail.
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.
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General Conditions
In the event of any conflict between the provisions of the Distribution
Code and the Grid Code relating to system Operation, the provisions of
the Grid Code shall prevail unless the Grid Code expressly provides
otherwise.
All Users are required to abide by the Distribution Code and 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.
A DSP may need access from a User across boundaries, services, and
facilities or may need to issue instructions to a User, for example to isolate
or disconnect Plant or apparatus. It is considered that the circumstances
and arrangements of these cases will be particular to each case and it is
therefore not possible to envisage precisely or comprehensively what a
DSP might reasonably require in order to carry out its duty. The DSP may
therefore make reasonable and specific access arrangements with Users
within bi-lateral agreements, for example Connection Agreements.
TIME OF EFFECTIVENESS
This Distribution Code shall have effect, as regards each User, at the
time at which its Connection Agreement comes into effect, except that
the provisions of the Planning Code and Connection Conditions to
supply data and follow Connection processes shall come into effect from
the time of application for a Connection or changed Connection.
UNFORESEEN CIRCUMSTANCES
If circumstances arise which the provisions of the Distribution Code have
not foreseen, a DSP 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, the DSP shall determine what is to be
done.
Whenever a DSP makes a determination it shall have regard, wherever
possible to the views expressed by the User, and in any event, to
what is reasonable in all the circumstances.
Each User shall comply with all instructions given to it by a DSP
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 shall
promptly refer all such unforeseen circumstances and any such
determination to the DCRP.
DISTRIBUTION CODE NOTICES
Any notice or compliance certificate to be given under the Distribution
Code shall be in writing and shall be duly given if signed by or on behalf of
a person duly authorised to do so by the party giving the notice or
compliance certificate and delivered by hand at, or sent by post, or
facsimile transmission or e-mail to the relevant address, facsimile number
or e-mail address last established pursuant to these General Conditions.
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General Conditions
The DSP shall maintain a list of contact details for itself and all Users
containing the telephone, facsimile, e-mail and postal addresses for all
Users. A DSP shall provide these details to any User in respect of any
other User as soon as practicable after receiving a request.
The DSP and all Users shall be entitled to amend, in any respect, their
contact details previously supplied and each DSP shall keep the list up to
date accordingly.
ILLEGALITY AND PARTIAL INVALIDITY
If any provision of the Distribution Code should be found to be unlawful
or wholly or partially invalid for any reason, the validity of all remaining
provisions of the Distribution Code shall not be affected.
If part of a provision of the Distribution Code is found to be unlawful or
invalid but the rest of such provision would remain valid if part of the
wording were deleted, the provision shall apply with such minimum
modification as may be:
necessary to make it valid and effective; and
most closely achieves the result of the original wording, but without
affecting the meaning or validity of any other provision of the
Distribution Code. A DSP or other party shall prepare a proposal to
correct the default for consideration by the Distribution Code
Review Panel.
DISTRIBUTION CODE REVIEW PANEL
Role of the Distribution Code Review Panel
The DSP(s) shall agree, and update as necessary with WERA, a
process to establish and maintain the DCRP, which shall be a standing
body, to carry out the functions referred to below. The Distribution
Code Review Panel (DCRP) shall:
keep the Distribution Code and its working under review,
review all suggestions for amendments to the Distribution Code
which WERA or any User may submit to a DSP for consideration by
the DCRP from time to time,
recommend to WERA amendments to the Distribution Code that
the DCRP feels are necessary or desirable and the reasons for the
recommendation,
issue guidance in relation to the Distribution Code and its
implementation, performance and interpretation when asked to do so
by any User,
consider what changes are necessary to the Distribution Code
arising out of any unforeseen circumstances referred to it by DSP(s)
under GC.6,
consider the effect of proposed changes on the Grid Code,
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
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General Conditions
produce an annual report of the activities of the DCRP.
Membership of the Distribution Code Review Panel
The DCRP shall consist of:
Chairperson and two persons appointed by, and representing
DSP(s) except that there should be at least one person representing
each licensed DSP,
one person appointed by and representing WERA,
one person representing the TSP,
one person representing Major Customers,
one person representing suppliers, and
one representative of the SASO,
one representative of KA CARE
If any of the above parties fails to appoint its representative, WERA
shall appoint one on its behalf.
Each of the above shall be appointed pursuant to the rules issued
under clause GC.9. The Distribution Code Review 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 Distribution Code Review
Panel”, which shall be approved byWERA.
The DSP shall consult all Users liable to be affected in relation to all
proposed amendments to the Distribution Code as per the standard
amendment form (which can be obtained throughWERA) and shall
submit all proposed amendments to the Distribution Code to the DCRP
for discussion prior to such consultation. Unless an amendment is
urgently required, WERA will not amend the Distribution Code until all
affected Users have been given a reasonable opportunity to make
representations to WERA concerning the amendment, and those
representations have been taken into account.
WERA will notify all DSPs and all affected Users of any amendment
that WERA makes to the Distribution Code.
DCRP shall, from time to time, or at the behest of WERA, having regard
to the recommendations of the Distribution Code Review Panel, submit
a revised Distribution Code to WERA for approval.
COMMUNICATIONS BETWEEN DSP(S) AND
USERS
Unless otherwise specified in the Distribution Code the methods of
operational communication and data transfer shall be agreed between
DSP(s) and each User from time to time.
EMERGENCY SITUATIONS
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 WERA in emergency situations, pursuant to provisions
of the Electricity Law issued by Royal Decree No. M/56.
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General Conditions
DEROGATIONS
Any User find that they are, or will be, unable to comply with any
provision of the Distribution Code. A Derogation may be granted by
WERA on the following grounds:
to provide for existing Plant that has not been designed in
accordance with the provision of the Distribution Code.
to facilitate a smooth transition to the Distribution Code from the
existing situation; and / or
to ease temporary constraints that prevent compliance and
necessitate exemption.
Request for Derogation
A User seeking a derogation from any provision of the Distribution
Code shall make a written request to the DCRP justifying the request in
terms of both the specific circumstances and the expected duration. As
a minimum, the application shall contain the following:
Details of the applicant;
relevant provisions of the Distribution Code and the required
performance;
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;
a description of the proposal for restoring compliance (where
applicable) including details of actions to mitigate risks and restore
compliance including timetable;
a description of the reasonable alternative actions that have been
considered; and
a statement of the expected duration of the non-compliance.
A standard Distribution Code Derogation Application Form can be
obtained through WERA.
The process for seeking derogations to the Distribution Code is
depicted in Figure 2.
User submits a
draft derogation
application
Submitted to the
DCRP
DCRP assesses
DCRP consults
expert if
required
WERA informs
DCRP of the
decision
WERA
considers and
makes decision
DCRP sends
recommendation
to WERA
DCRP finalises
its review
DCRP informs
the decision to
the User
DCRP takes
appropriate
action
Figure 2: Distribution Code derogation process
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General Conditions
Consideration of a Request for a Derogation
On receipt from WERA of any request to advice on a derogation, the
DCRP shall promptly consider such request and discuss the potential
outcomes of such requestand submit its recommendation(s) to WERA
for a final decision.
WERA shall consider the request in light of the recommendation(s) of
the DCRP and shall decide as appropriate. In deciding on the request,
WERA may invite the User any member of the DCRP to seek
clarification on the application.
WERA shall communication its final decision to the DCRP for
informating the User and / or taking further action, as appropriate.
If a derogation is granted, then the User will not be obligated to comply
with the applicable provision of the Distribution Code for the period of the
derogation and shall comply with any alternative provision as set out in the
derogation.
Expiry date of the derogation
A derogation from the Distribution Code will normally have an expiry date
in order to review its continued need and monitor performance towards
compliance. It is the responsibility of the User to ensure compliance is met
in line with the defined timeline.
Maintaining a register of derogations
Every derogation will be entered on a register and maintained by WERA
for this purpose.
Non-transferable derogations
A derogation is granted to a User and is not transferable to another User.
If a Plant is sold, the new User will need to seek a new derogation.
Material changes to the conditions of the derogation
Where a material change in the circumstances of the derogation
occurs, a review of any existing derogation, or any derogation under
consideration, may be initiated by WERA or at the request of the User.
CONFIDENTIALITY
The Distribution Code contains procedures under which a DSP will
receive information from a User relating to the intentions of such User.
The DSP shall not, except as provided for in the Planning Code of this
Distribution Code or as agreed in writing with the User, 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 Licence or the express requirement of any court of law.
The Constitution and Rules of the DCRP shall ensure that each Member
of the DCRP is bound by appropriate levels of data confidentiality in
respect of any data received for a DSP or User.
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General Conditions
FORCE MAJEURE
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.
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.
DISPUTES & DISPUTE RESOLUTION
PROCEDURE
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 GC.15.
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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Planning Code
PLANNING CODE
CONTENTS
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Planning Code
INTRODUCTION
This code sets out the roles and responsibilities of DSP(s) and Users
regarding the data to be exchanged and the procedures to be complied
with, to enable the planning and development of the Distribution System,
and to facilitate Users in the planning and development of their
installations as far as they affect the Distribution System.
The Planning Code is required to define the planning process that shall
occur annually, covering the load forecast plans for the succeeding five
Operational Years (Distribution Capability Statement) in order to
provide sufficient lead times to facilitate the implementation of a DSP’s
network development strategy including:
any necessary planning or consent work; and
detailed engineering design/construction work to be completed by
DSP(s) and existing or potential Users of the Distribution System.
OBJECTIVE
The objectives of the Planning Code are to define the roles and
responsibilities of DSPs and Users to enable:
the exchange of information and interaction between DSPs and
Users concerning any proposed development of a User system that
is to be Connected to the Distribution System, or that may have an
impact on the performance of the Distribution System or the
Transmission System;
any proposed development by a User that may have an impact on
the performance of the Distribution System or the Transmission
System to be carried out in a manner that will allow DSPs to meet
their obligations as defined in the Distribution license;
the supply of information to allow DSPs to undertake their planning
duties as set down in their licenses and Sector Law; and the supply
of information to the TSP to allow it to fulfil its License obligations.
In addition, the Planning Code briefly describes the process relating to
entering into, and modification of Connection Agreements.
SCOPE
User requirements may necessitate the reinforcement of, or an extension
to, the Distribution System and reinforcement of, or extension to, the
relevant Transmission/Distribution interface capacity, such work
identified by DSP or the TSP as appropriate.
Time needed to plan the Distribution System and User
systems
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 Saudi Arabian Distribution Code
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Planning Code
the time required for obtaining planning permission and right-of-way
(including any associated hearings); and
the degree of complexity in undertaking the work while maintaining
satisfactory security and quality of supply.
Reference is made in PC.7 to the DSP supplying information or advice to
Users. For avoidance of doubt, unless the context otherwise requires,
such information or advice shall be provided by DSP as soon as practical
following a request by the User (whether during the application for
Connection process or otherwise).
DSP and Connected Users
In addition to DSPs, the Code applies to the following Users:
Power Producers of all types Connected to the Distribution
System at any Voltage;
All Demand Users;
Licensed Retailers; and
Licensed Traders.
Parties not yet Connected
Persons whose future activities would place them in any of the categories
of User listed above will, either:
on receiving an approval from a DSP to be Connected; or
as a result of the application procedure for a Connection
Agreement or other agreement,
become bound by the PC.
PLANNING PROCEDURES AND STANDARDS
Time to plan and Connect
Time needed to plan and develop
The time required for planning and developing 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 rights of way (including any associated hearings),
and the degree of complexity in undertaking the new work while
maintaining satisfactory security and quality of supply. In general,
approved works on the Distribution System can be achieved within 5
years.
Time to supply information to Users
Reference is made in PC.7 to DSPs supplying information or advice to
Users. For avoidance of doubt, unless the context otherwise requires,
such information or advice shall be provided by the DSP as soon as
practical following a request by the User (whether during the application
for Connection process or otherwise).
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Planning Code
Design standards
The Distribution System is designed to perform in accordance with the
following standards.
Frequency
The Frequency of supply on the Interconnected System is outside the
control of DSPs, however the standard Frequency is nominally 60Hz and
shall normally be controlled within the limits of 59.9Hz to 60.1Hz;
The Frequency on the Interconnected System could rise to 62.5Hz or
fall to 57.0Hz in exceptional circumstances. Design of Power Producer’s
Plant and apparatus must enable Operation of that Plant and apparatus
within that range in accordance with the following Table 1.
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 a period of 30 minutes
57.0 – 57.4
61.6 – 62.5
For a period of 30
seconds
Table 1: Frequency capability requirements for power producing Plant
Other Users should ensure their equipment is designed or protected for
these exceptional circumstances.
The Frequency on parts of the Distribution System not interconnected
by the Transmission System, either permanently or temporarily, will be
maintained as if that part of the Distribution System is Connected to the
Transmission System. Power Producers and other Users must ensure
that their Plant and apparatus so complies.
Voltage
Standard Voltage
The Voltages listed in Table 2 shall be used as standard service Voltages
at the interfaces with Customers. The service Voltage shall be
maintained on an average basis for each 10-minute period, 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
Distribution System.
Where two Voltages are listed, e.g. 220/127V the lower value refers to the
phase to neutral Voltage. All other values are phase-to-phase Voltages.
The Voltages in Table 2 are based upon nominal Voltage ± 5% to allow
for the normal variation with load and load distribution.
Nominal Voltage
Lowest Voltage
Highest Voltage
220 / 127 V
209 / 120V
231 / 134V
380 / 220 V
360 / 209V
400 / 231V
400 / 230 V
380 / 218.5V
420 / 241.5V
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Planning Code
Nominal Voltage
Lowest Voltage
Highest Voltage
13.8kV
13.1kV
14.5kV
33kV
31.4kV
34.7kV
69kV
65.5kV
72.5kV
Table 2: Standard service Voltage
Note: 1 the change of the old system 220 / 127V to the new system 400 / 230V in
ongoing projects and facilities will be completed within 25 years as per Council of
Ministers No. 324 dated 20/9/1430. The 220 / 127V system will then be obsolete.
Non-standard Voltages
Existing, but non-standard, Voltages are listed in Table 3.
The service Voltage shall be maintained on an average basis for each 10minute period 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 3: Existing, but non-standard Voltage
Harmonics
The maximum planning level of Harmonics in the power system on a
continuous basis is set out in Table 4, Table 5, Table 6 and Table 7.
Nominal Voltage
Total Harmonic Distortion (%)
230 – 400V
5.0
127 – 220V
5.0
11kV & 13.8kV
4.0
33kV-69kV
3.0
Table 4: Maximum continuous Total Harmonic Distortion levels expressed in % of
Voltage at fundamental Frequency
Individual Harmonic planning level limits for LV Distribution Systems up
to 1kV are shown in Table 5.
Odd Harmonics
(Non-multiple of 3)
Odd Harmonics
(Multiple of 3)
Even Harmonics
Order 'h'
Harmonic
Voltage %
Order 'h'
Harmonic
Voltage %
Order 'h'
Harmonic
Voltage %
5
7.4
3
5.0
2
1.5
7
5.5
9
1.5
4
0.9
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Planning Code
11
3.5
15
0.4
6
0.7
13
3.0
21
0.3
8
0.6
17
2.3
>21
0.2
10
0.5
19
2.0
>12
0.4
23
1.7
25
1.5
>25
(38.5/h-0.27
Table 5: Distribution System at Voltages up to 1kV - maximum continuous individual
Harmonic distortion planning levels expressed in % of Voltage at fundamental
Frequency
Individual Harmonic planning level limits for the Distribution System
>1kV and ≤35kV as shown in Table 6 below.
Odd Harmonics
(Non-multiple of 3)
Odd Harmonics
(Multiple of 3)
Even Harmonics
Order 'h'
Harmonic
Voltage %
Order
'h'
Harmonic
Voltage %
Order
'h'
Harmonic
Voltage %
5
6.3
3
4.0
2
1.5
7
4.4
9
1.2
4
0.8
11
2.7
15
0.3
6
0.6
13
2.3
21
0.2
8
0.5
17
1.7
>21
0.2
10
0.5
19
1.5
12
0.4
23
1.2
14
0.4
25
1.1
16
0.3
>25
(32.3/h) -.0.2
>16
(2.5/h)+0.2
2
Table 6: Distribution System at Voltages >1kV and ≤35kV - maximum continuous
individual Harmonic distortion planning levels expressed in % of Voltage at fundamental
Frequency
Individual Harmonic planning level limits for the Distribution System
>35kV and ≤69kV are shown in Table 7 below
The Saudi Arabian Distribution Code
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Planning Code
Odd Harmonics
(Non-multiple of 3)
Odd Harmonics
(Multiple of 3)
Even Harmonics
Order 'h'
Harmonic
Voltage %
Order 'h'
Harmonic
Voltage %
Order 'h'
Harmonic
Voltage
%
5
4.1
3
2.0
2
1.1
7
2.9
9
1.0
4
0.6
11
1.9
15
0.3
6
0.5
13
1.6
21
0.2
8
0.4
17
1.2
>21
0.2
10
0.4
19
1.1
12
0.3
23
0.9
14
0.3
25
0.8
16
0.3
>25
20.4/h
>16
1.9/h+0.16
Table 7: Distribution System at Voltages >35kV and ≤69kV - maximum continuous
individual Harmonic distortion planning levels expressed in % of Voltage at fundamental
Frequency
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 1% of the positive
phase sequence Voltage.
System Earthing
The method of Earthing of the Distribution System and any appropriate
values shall be stated by the DSP in any Offer of Terms for Connection
and in the Connection Agreement with any User.
The Distribution Systems may be directly Connected to Earth or
Connected through an impedance.
Annual planning
A timetable for the supply of annual update data is in Appendix A.
Planning the system
The Distribution System is planned in accordance with the Security of
Supply Standards as amended from time to time (Appendix C) and
approved by WERA.
The DSP shall comply with the current Security of Supply Standards or
seek a derogation from WERA for specific cases.
Operating the System
The following information is provided to guide DSPs and to enable Users
to plan any additional security measures needed for their processes.
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Planning Code
The DSP shall use reasonable endeavours to maintain a reliable supply
from the system to Customers. This cannot be ensured at all times, since
faults, planned maintenance, new works outages or other circumstances
outside the DSP’s control can cause interruptions. On such occasions, the
DSP shall use reasonable endeavours 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.
Planned restoration times for different outage types are in Table 8 below.
Fault Outages:
The DSP shall endeavour to restore access to the system
as soon as practically possible.
Planned
Outages
The DSP 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 extreme cases where this may not be
possible, the DSP shall endeavour to provide two-day
notice to the User.
In extreme situations, there may be generation shortages
and load shedding may be required. In these
circumstances, the DSP shall notify Customers if possible
but as this is an emergency, it may not be possible to do
so.
Load Shedding:
Each DSP shall prepare load shedding criteria in approved
form (Planning Code Appendix H) and updated as
required and shall submit it to WERA for approval. These
criteria shall detail the methodology for selection of load(s)
to be shed, including but not limited to, the history of load
shedding, the criticality and characteristics of load and the
generation/load balance of any load shedding block or
zone.
Upon request, a DSP shall make available to WERA or any
other User or Customer a statement showing the present
order of load shedding and shall, on request, keep such
parties updated as often as that order shall be changed.
Table 8: Planned restoration times for different outage types
SYSTEM ANALYSIS AND DEVELOPMENT
The need for development of the Distribution System
The need for analysis and development of the Distribution System,
involving its reinforcement or extension, may arise for a number of
reasons including, but not limited to:
a development on a User system already Connected to the
Distribution System;
the introduction of a new Connection site or the modification of an
existing Connection site between a User system and the
Distribution System;
The Saudi Arabian Distribution Code
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Planning Code
changing requirements for electricity distribution facilities due to
changes in factors such as Demand, generation, technology,
reliability requirements and/or environmental requirements;
stability or Fault Level considerations and other power system
studies to ensure efficient, safe, reliable, and economic Operation of
the Distribution System or the Total System;
the aggregate effect of Customer developments; and/or
the cumulative effect of any combination of the above.
Reinforcement or extension of the Distribution System
Accordingly, the reinforcement or extension of the Distribution System
may involve work:
at a Connection site where one or more User’s Plant is Connected
to the Distribution System;
on cables, lines or other facilities which join that Connection site to
the remainder of the Distribution System;
on distribution lines or other Plant at locations remote from that
Connection site; and / or
at any location of Connection with the Transmission System.
A further requirement for analysis arises because DSPs are required by
WERA to produce an annual Distribution Capability Statement setting
out how User needs for system capacity will be met throughout the
following five year period whilst maintain the level of security set down in
the Security of Supply Standards in Appendix C. The TSP is also
required by licence to perform similar studies requiring information from
DSPs related to their Distribution Systems, Connected or projected
Demand and generation.
PLANNING DATA FROM USERS
Obligation for Users to provide data
The Connection Conditions indicate the minimum required performance
for Users’ Plant and equipment (including Generating Units and
Disturbing Loads) whereas this chapter - the Planning Code is
concerned with the obligation placed on Users to supply data to the DSP,
both initially and on an on-going basis, to allow the DSP to ensure that the
performance requirements are being fulfilled and to perform the tasks set
out in PC.5 above.
Users of the Distribution System shall provide sufficient planning data/
information as can reasonably be expected to be made available, when
requested by the DSP from time to time, to enable the DSP to comply with
the requirements under its Distribution Licence.
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 the Operating Code.
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Planning Code
Notice of Significant Change to User System
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 the DSP to prepare its development plans and shall
implement any necessary system modifications. In the event of unplanned
changes in a User’s system or operating regime, a User shall notify the
DSP as soon as is practically possible to ensure any necessary
accommodating measures can be implemented.
Provision Good Quality Data
Users must provide good quality data to the DSP. Users who have not yet
decided upon particular equipment may need initially to supply generic
data, but the status of this data must be identified to the DSP and accurate
data provided at the earliest opportunity. Where actual data differs
significantly from data supplied to the DSP, the DSP may withdraw an
offer and require the User to resubmit an application for Connection or
modification. Where a User fails to notify the DSP and/or provide good
quality data concerning a modification, creating risk to the Distribution
System, the DSP may seek to apply the provisions of PC.9 to all or part of
the Users’ installation.
To enable the Distribution Capability Statement to be prepared, each
User is required to submit to its DSP the Data listed in Schedules C, D
and E (excluding such asset Standard Data or Detailed Planning Data
which has remained unaltered since the previous submission.)
Types of Data
The Planning Data required from Users is allocated to one of two
categories:
Standard Data
Standard Data covers basic Demand data or size and type of
Generating Units to allow the DSP to carry out load flow and short-circuit
studies to determine any requirements to reinforce the Distribution
System or to discuss with the TSP the adequacy of the Transmission
System and to allow preliminary assessment of the need for stability
studies. Standard Data is so identified in the Schedules.
Detailed Planning Data
Detailed Planning Data covers additional data to allow detailed stability
studies to be carried out as necessary. Detailed Planning Data is so
identified in the Schedules.
Data status level during the Connection process
Planning Data supplied by Users applying for a Connection Agreement
or for a modification to a current Connection Agreement is allocated to
one of three status levels, as follows:Preliminary Project Planning Data
Preliminary Project Planning Data supplied on application which will
normally contain only Standard Planning Data, unless elements of
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Planning Code
Detailed Planning Data are required in advance of the normal timescale
(to enable a DSP to carry out additional detailed system studies).
Committed Project Planning Data
Once an offer for a Connection Agreement is accepted, the data relating
to the User development already submitted as Preliminary Project
Planning Data, and the subsequent data required by the DSP, will
become Committed Project Planning Data. These data, together with
the other data held by the DSP relating to the Distribution System will
form the background against which new applications by any User will be
considered and against which planning of the Distribution System will be
undertaken. Committed Project Planning Data may contain both
Standard Planning Data and Detailed Planning Data.
Connected Planning Data
When any estimated values assumed for planning purposes are confirmed
or replaced by validated actual values, these data are then termed
Connected Planning Data. Accordingly, Connected Planning Data may
be used and disclosed by the DSP in the same manner and to the same
extent as Committed Project Planning Data. Connected Planning Data
may contain both Standard Planning Data and Detailed Planning Data.
Data Confidentiality
Committed Project Planning Data and Connected Planning Data,
together with the other data held by the DSP relating to the Distribution
System, will form the background against which new applications by any
User will be considered and against which planning of the Distribution
System will be undertaken. Accordingly, data will not be treated as
confidential to the extent that the DSP.
is obliged to use it in the preparation of the Distribution Capability
Statement;
is obliged to use it when considering and/or advising on applications
by other Users if the data is relevant to that other application; and
is obliged to use it for the DSP operational planning purposes.
All other data (for the avoidance of doubt, including Preliminary Project
Planning Data) will be treated as confidential.
Where Committed Project Planning Data or Connected Planning Data
includes detailed models related to the Operation and control of Plant or
equipment and a User considers the data to be commercially sensitive,
the User may request the DSP to sign an agreement related to the
confidentiality of that information, but such agreement shall not prevent the
DSP from using the information for any reasonable purposes of the DSP in
discharge of its Licence obligations.
Data required from all Users
All Users must complete details of their location, interface equipment and
interface Protection. Additionally, Users with MV equipment must provide
sufficient information to enable the DSP to assess transient overvoltage
analysis. This information is in Schedules A and B.
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Users with Complex or MV Connection arrangements must provide
details of their interface equipment and ownership and control diagrams
and additionally record the drawing references on Schedule B.
Users with Complex interface arrangements and MV Connections must
provide and maintain as current, a list of senior managers, Safety
Coordinators, Competent Persons and a nominated person in case of
emergency and must provide a means of contact with those persons
(CC.5.3)
On request from the DSP, a User shall supply sufficient details with
respect to the User/DSP Ownership Boundary to enable an assessment
to be made of transient overvoltage effects.
Requirement for a Statement of Compliance
Prior to Connection a User must supply an itemised statement of
compliance with the Distribution Connection Conditions and such other
Distribution Code matters as apply to that User. The statement of
compliance must be provided in a format approved by the DSP (See
CC.6.2.2).
The DSP has the right to require any or all of the following data from
Users. Where the DSP requires the data, the User must provide it as
stated in PC.6.6 to PC.6.13 below.
Users with Demand
Users with Demand must also provide the information in Schedule C of
the PC.
Users with Demand are required to provide Demand patterns and
forecast Demand for each of the five succeeding calendar years as set
down in Schedule D and E of the PC and to update these Schedules
annually. Users must complete and submit these Schedules whether or
not they reasonably believe there will be a change in the present data.
Users with large motors, which contribute, to Fault Level on the
Distribution System should complete Schedule F.
Users with Controllable Demand and Demand Transfer
Capability
Users with Controllable Demand are required to complete the
appropriate section of Schedule E, which indicates how much of their
Demand is controllable and any special features or limitation of the
Demand or control arrangement. Users must also state the period of any
contracted arrangement to control the Demand and any contractual
limitations.
Users with Demand Transfer capability (where the same Demand can be
supplied from alternate User points of supply) shall provide, and keep
updated, information relating to that Demand including the proportion of
Demand normally fed from each point of supply and the arrangements
(manual or automatic) for transfer under planned/fault outage conditions
as in Schedule E.
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Users with Disturbing Loads
Users with Disturbing Loads including DC drives should first seek
information about the Fault Level at their point of Connection to the
Distribution System must then provide the information in Schedule C
together with evidence of the assessment.
Power Producers
Users with Generating Units must advise which of their Generating
Units are traditional units - Synchronous and which Asynchronous
including induction generators –Type A – without electronics and all other
Asynchronous – Type B (in Schedules A and G).
Power Producers must complete Schedule F indicating their Fault Level
contribution. Power Producers must complete schedule G or Schedule H
or Schedule I for each Generating Unit showing the characteristics of that
Generating Unit and must additionally complete a schedule indicating the
maximum capability of the entire site (which could in certain circumstances
be less than the sum of the Generating Units located on the site).
Schedule H requires Users to define the fuel or renewable source and, if
fossil fuel is used, any intended pattern of use of the Generating Units
and, under operational data rather than planning data, any intended period
of absence from service. The schedules also require Users to provide
sufficient information to allow the DSP to conduct Fault Level, transient
and dynamic studies.
The DSP will use the information provided to model the Generating Unit
to determine a technically acceptable method of Connection. If the DSP
reasonably concludes that the nature of the proposed Connection or
change to an existing Connection requires analysis that is more detailed
then further information than that specified in the schedules may be
required.
Retirement of Generating Units
Power Producers are also required to indicate whether they intend to add
or retire Generating Units within the following five-year period. Unless
changed from previously submitted data, Power Producers need not resubmit, on an annual basis, the Standard Data and Detailed Data for
their Generating Units.
Users with both Demand and Generating Units
Users with Demand and Generating Units shall complete the appropriate
schedules for each. The DSP may seek further information regarding the
pattern by which Users intend to offset their Demand or deliver energy to
the network.
Users with Energy Storage Units
An Energy Storage unit is at times a Generating Unit and at times
Demand or Controllable Demand. The appropriate Schedules are
therefore to be completed by such Users taking account of any expected
deterioration in performance over the subsequent five-year period.
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Users with electric vehicle charging
This type of Connection is treated as one of Demand, Controllable
Demand, or Controllable Demand with a Generating Unit, depending
upon whether it is possible to use the stored energy in the vehicle
batteries to re-supply the Distribution System. The User should
complete the appropriate Schedules for Demand, Controllable Demand
and the relevant Power Producer Schedules.
PLANNING DATA REQUIREMENTS FROM THE DSP
DSP obligation to supply data
On request from a User, the DSP shall provide such information as may
be reasonably required related to the design and characteristics of the
Distribution System.
Where a DSP proposes to make certain modifications to its system or
where it has received information from a User under PC.6 above, which
may affect other User installations then the DSP will notify affected Users
of the proposal, subject to any constraint of confidentiality or timing.
Data to be supplied
Connection Voltage
The DSP shall state the Voltage at which a User may be Connected
following discussions and considering the factors in CC.6.2.3.
Specific Data to enable a User to design the User System and equipment
Following an application for supply, or on request of a User, or following a
material change in the Distribution System, the DSP will provide some or
all of the following information to enable Users to assess their systems:
the source impedance under maximum capacity conditions for each
Connection Point;
the source impedance under minimum capacity conditions for each
Connection Point;
updated information on circuit re-closing, Protection principles and
settings needed to ensure co-ordination of Protection between the
Distribution System and the User system(s);
Demand Transfer Information
Where the same Demand can be supplied from alternate User points of
supply the DSP shall provide sufficient information to enable the User to
complete the appropriate section within the User Demand Schedule E
Point 2.
Earthing Information
The DSP shall advise the User 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 apparatus and Plant as a result of the method of
Earthing.
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Notwithstanding the above, the DSP shall provide an Earthing Code to
define the Earthing requirements for safe use of the system. This code
shall constitute an integral part of the Distribution Code.
PROCEDURES FOR CONNECTION / DATA
REQUIRED & DATA CONFIDENTIALITY
Distribution Capacity Statements
Where such information is available the DSP shall provide, on request, a
statement of present and future circuit capacities, forecast power flows
and loadings on the part or parts of the Distribution System specified in
the request and shall include Fault Levels at each Distribution node
covered by the request.
The DSP may levy a charge for the provision of this statement as
approved by WERA reflecting the reasonable costs incurred by the DSP 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 later. In the case of Power
Producers and Major Customers, seeking Connection this period may
be extended to 100 days depending on the nature and complexity of the
request.
Connection Procedures
Details of the procedures for application for Connection to the
Distribution System are contained in the ESPM as prepared by the DSP
and approved by WERA.
Users shall contact DSPs in advance if it is proposed to make any
significant change to the Connection, their electric lines or electric
equipment, or to install or operate any generating equipment or do anything
else that could affect the Distribution System or require alterations to
Connection.
Connection Studies
To facilitate Connections to the Distribution System, the DSP shall
prepare, on request, a study showing the implications of a Connection at
a particular point on the system.
All charges made by DSPs for studies or Connection and timeframes for
studies and work shall be in line with each Licensee’s Charging Statement
agreed with WERA.
A User or potential User shall provide the DSP, in good time, with
information in PC.8.4 below and as further specified in the Schedules to
this PC, the proposed facility including load details, interface
arrangements, proposed Connection Point and import/export
requirements.
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Preparation of Network Studies
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 later. In the case of
Power Producers, seeking Connection, depending on the nature and
complexity of the request, this period may be extended up to 56 days or in
some cases up to 100 days, from receipt of the information or the
agreement of the person making the request to pay the cost of the study
or the receipt of planning information from the TSP whichever is the
greater. The dates given in this PC.8 are target dates only and do not
constitute a legal commitment. DSPs shall however use reasonable
endeavours to abide by them.
Where the circumstances demand significant time extension, the DSP
may agree this with the User or where no agreement can be reached
apply to WERA for a variation to this clause.
User Data Required for Connection Assessment / Studies
Low Voltage Connections
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:
maximum kVA requirements see Schedule C1;
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, see Schedule C1;
Users who have reactive compensating equipment above 20kVAr
should complete Schedule B2;
if applicable, type and electrical rating of Generating Unit to be
Connected, such as, for an Asynchronous Generating Unit, the
number, size of PV inverter (Schedule I), CHP generator see
Schedule G;
if applicable, the expected performance, during and immediately after
faults on the relevant part of the LV system, of a Generating Unit to
be Connected – Schedule F and where appropriate fault ride
through model;
when requested by the DSP, typical daily and seasonal load and
generation patterns see Schedule D1 and D2;
single-line diagram of the installation - see Schedule B1;
for Complex arrangements at the interface position, details of
switchgear -Schedule B3;
the date when Connection is required; and
a plan showing the area covered by the installation and the location.
If a preliminary examination of this data indicates that more Detailed
Planning Data is reasonably required then it shall be provided to the DSP
upon request.
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Connections MV
For Connections at MV, the provisions of PC.8.4.1 apply. Additionally, the
following information is required from Users, unless provision of part or all
the data is excused by the DSP:
User MV System Data
The characteristics of User’s switchgear at the Connection Point;
Where a User has a User system involving significant amounts of network,
the effects of the User network on the Distribution System may need to
be modelled by the DSP. The User should in the first instance model the
User system and provide such model to the DSP. The DSP may wish to
check the model, in such case, Schedule B point 4 should be completed
by the User. For this purpose, the characteristics of the User network are
modelled as User Demand.
Where a User has connecting transformers, these may need to be
modelled by the DSP. Such Users are to provide a transformer and
Voltage control model and if requested data as in Schedule B point 5.
Protection data related to the interface of the User system with the
Distribution System as in Schedule B point 6.
On request, sufficient transient overvoltage data for equipment at the
interface with the Distribution System as detailed in Schedule B point 7.
Reactive Compensation Equipment
All MV Users with reactive compensation equipment should complete
Schedule B point 2.
All Types of Demand
Maximum Active Power requirements. Schedule C;
Maximum and minimum Reactive Power requirements. Schedule C;
Type of load and control arrangements (e.g. type of motor start,
controlled rectifier or large motor drives) see PC.8.4.2.4 below
Schedule C; and
Maximum loading on each phase. Schedule C point 1.
Disturbing Loads
Users must provide a comprehensive schedule of installed new
equipment including details of Disturbing Loads. 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 is contained in Schedule C point 3.
In the case of compensating equipment associated with Disturbing
Loads, details and mode of Operation are to be provided to ensure
compliance with emission limits specified in CC.8.1.6.
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Equipment which produces Harmonic current emissions
Users with such Generating Units or Loads must state that the
equipment is compliant with the requirements of the Connection
Conditions, when Connected to the compliant (assessed by planning
levels) Distribution System. Users with equipment of size or type, which
might create disturbance, must state the level of Harmonic emissions in
Schedule C point 6.
Phase Unbalance
Users must state in Schedule C point 5, the expected maximum and
average percentage in phase unbalance currents at the Connection
Point.
Fluctuating Loads
Users with fluctuating loads must state the duty cycle, including details of
cyclic or other variation of Active Power and Reactive Power, in
particular:
the rates of change of Active Power and Reactive Power, both
increasing and decreasing;
the shortest repetitive time interval between fluctuations in Active
Power and Reactive Power; and
the magnitude of the largest step changes in Active Power and
Reactive Power, both increasing and decreasing.
Schedule C point 3 should be completed for Users with these types of
equipment.
Information from all Power Producers
For all types of generation, the information requested in Schedules F, G,
H, I or J (Synchronous and Asynchronous) is to be provided.
In normal circumstances, the information specified below and further
identified in the Schedules A to J to this PC will enable DSPs to assess the
Connection requirements. Occasionally additional information may be
required. In such circumstances, the Power Producer, at the reasonable
request of the DSP, shall make the information available.
Information to be Supplied to the DSP
The information to be supplied to the DSP includes:
1
2
3
4
5
the type of Generating Units proposed (e.g. Asynchronous
Generating Units);
where the power production site is Complex, how these Generating
Units are arranged and protected and in the case of Solar
Asynchronous Generating Units the arrangement and size of PV
panels, the rating of inverters and their complete technical data;
the terminal Voltage and rating in kVA of the Generating Unit;
the maximum (and, if appropriate minimum stable) MW Output of the
Generating Unit;
the kVAr or MVAr capability of the Generating Unit;
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Planning Code
6
7
the maximum Active Power sent out and any Reactive Power
requirements for the User site;
information regarding the control arrangements and capability for:
8
if appropriate, the starting current and the Power Factor during
starting and after faults;
9
the short-circuit contribution of the Generating Unit;
10 maximum phase-imbalance and Harmonic currents which may be
imposed on the Distribution System during starting and normal
Operation;
11 the arrangements for Synchronising a Synchronous generator;
12 dynamic modelling information for Asynchronous Generating Units
including dynamic models;
13 on request, details of fuel used and Generating Unit efficiency;
14 details of generator transformers or site transformers; and
15 any envisaged operating regime.
Additional Information to be Supplied to the DSP
Additional information may be required from Power Producers with
Generating Units having a Registered Capacity greater than 2MW or
Connected at a Voltage level at MV as follows:
1
Automatic Voltage Regulator (AVR) data
2
Speed Governor and Prime Mover data
3
Generating Unit and User installation Demand (Active Power and
Reactive Power) in MW and MVAr, under minimum generation
conditions.
Power Producers with all types of Generating Units must declare
Reactive Power / Power Factor capability at the Connection Point.
Provision of a Protection Philosophy
Power Producers must additionally supply to their DSP a Protection
philosophy document together with a list of proposed settings for their
protective relays and devices as part of the Connections Process
(CC.8.2).
Power Producers must declare Demand data including Disturbing
Loads.
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Planning Code
Power Producers should as early in the Connection process as possible
provide the information required in CC.5.2-Information needed prior to
completion.
Additional Information for Connection
In some cases, information that is more detailed may be required to permit a
full assessment of the effect of a User’s load on the Distribution System.
Such information may include an indication of the pattern of buildup of
load over time (Schedule D1 & D2) and a proposed commissioning
program. This information shall be specifically requested by DSP(s) when
necessary and shall be provided by the User within a reasonable time.
Users shall provide their DSP with any information reasonably required by
the DSP about the nature, or use by the User, of electrical equipment on the
User’s premises.
Users seeking a new or modified Connection Agreement
Based on the information provided by the User for a Connection to the
Distribution System, the DSP shall prepare a statement containing as
many of the following elements as are necessary for, or relevant to, the
proposed installation:
1
2
3
4
5
6
7
8
nominal Voltage at which Connection will be made;
method of Connection, extension and/or reinforcement details and
including details of any acceptable Demand Transfer Arrangements;
the normal source impedance at the point of Connection;
method of Earthing;
maximum import capacity;
individual Customer limits relating to
expected lead time of providing Connection (following formal
acceptance of terms for supply); and
Cost of Connection.
Either as part of the statement or otherwise, on request from the User, the
DSP shall also make available sufficient details with respect to the
User/DSP Ownership Boundary to enable an assessment to be made of
transient overvoltage effects.
DISCONNECTING USERS
DSP(s) may disconnect Users under certain circumstances. These
circumstances shall include:
1
where the Customer’s installation or use of electricity is such as to
interfere with the satisfactory Operation of the Distribution System
or Transmission System or to cause disturbance to other
Customers;
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Planning Code
2
3
4
5
where DSP(s) considers that the Customer’s installation is in a
dangerous condition;
where alterations, repairs, renewal or maintenance of the
Distribution System or the DSP’s assets or means of Connection
require the de-energization of the Connection Point and subject to
requisite notice periods as set down in the ESPM;
where a Customer extends supply for use by another party whom
the DSP considers to be a separate Customer; and/or
in any other circumstances in which discretion is necessary or
appropriate to enable DSPs to comply with the Distribution Code
and/or to operate the Distribution System in accordance with Good
Industry Practice.
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Planning Code
Appendix A – Timetable for supply of data
Annual data
Submission
date
Schedule
D1 – User Demand profiles – daily load
D2 – User Demand profiles – weekly and seasonal load
D3 – Generating Unit Output Available and Controllable Demand
profiles – Daily Output usable and/or Controllable Demand
D4 – Generating Unit Output usable and Controllable Demand
profiles – weekly and seasonal load
K – Outage schedules
Data supplied at initial Connection or in the case of a
change of data
Schedule
Submission date
A – User system data
initially
B – User system data
initially
C – load characteristics data
Initially unless
changed
E – Connection Point data
initially
F – Fault infeed data
initially
G – Generating Units >100kW data
initially
H – Synchronous generators data
initially
I – Asynchronous generators data
initially
J – Energy Storage units
initially
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Appendix B – User data schedules
User data schedules
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Schedule A: - User system data – All Users
Name of business
Name of responsible person
Telephone
Location of Connection Point
Date first Connected or to be Connected
The following table to be completed by all Users indicating which Planning Schedules have been returned to DSP(s) and the date of the latest return.
The marking shows the DSP’s expectation.
Type of User
Schedule
B
C
D
E
F
User with Demand
(excludedsMinor
Customer’Minor Customers)
X
X
X
X
X
User with Synchronous
Generating Units
X
Users with Asynchronous
Generating Units
X
Users with Energy Storage
X
X
G
H
X
X
X
X
X
X
# If synchronous
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X#
X
I
J
X
X
X
X
Planning Code
Schedule B: - User system data - Demand (Standard Data)
Correct for
(Date)
To be completed by All Users (Users to provide technical data sheets where available)
The following current and forecast details that relate to the Connection site containing the Connection Point are required from each User on its User
system. Any change in forecast data should be recorded on a separate copy of this Schedule with the change date clearly identified.
Data description
Single line diagram:
1
Units
Connection
Data
User to Complete
Drawing
All Voltages
reference
Required for all MV or Complex Connection.
Single line diagram showing all existing and proposed Connection equipment and Connections together with equipment ratings;
Reactive compensation equipment:
2
All Voltages
Required for all Users with reactive compensation.
For all reactive compensation equipment Connected to the User system at specified Voltage and above, other than Power Factor correction
equipment associated directly with a Customer Plant, the following details;
2.1
Type of equipment (e.g. fixed or variable);
Text
2.2
Capacitive rating;
kVAr
2.3
Inductive rating;
kVAr
2.4
Operating range;
kVAr
2.5
Details of any automatic control logic to enable operating characteristics
to be determined including dead bands or control intervals and set points;
Text and/or Diagrams
2.6
Connection Point to the User System in terms of electrical location and
System Voltage;
Text
2.7
Total Harmonic Distortion and Harmonic penetration at specified
Frequencies at the Connection Point and details of de-tuning installed.
Table of % Harmonic
current at each
Frequency, text,
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Text or reference
Text or reference
Reference to table
Planning Code
diagram of de-tuning
Switchgear
3
Required for all Users
For all switchgear (i.e. Circuit Breakers, switch disconnectors and isolators) on all circuits Directly Connected to the Connection Point including
those at Production Facilities;
3.1
Rated Voltage
V or kV
3.2
Operating Voltage
V or kV
Rated short-circuit breaking current
kA
Single phase
kA
Three phase
kA
Rated load breaking current
kA
Single phase
kA
Three phase
kA
Rated peak short-circuit making current (symmetrical and asymmetrical)
kA
Single phase
kA
Three phase
kA
3.3
3.4
3.5
User MV Connecting System data Circuit Parameters (for all circuits).
4
For all Systems at 11kV and above Connecting the User system to the Distribution System, the following details are required relating to the
Connection Point.
4.1
Rated Voltage;
kV
4.2
Operating Voltage;
kV
Positive phase sequence;
4.3
% on 100 MVA base
Resistance
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Reactance;
% on 100 MVA base
Susceptance;
% on 100 MVA base
Zero phase sequence;
Resistance
% on 100 MVA base
Reactance;
% on 100 MVA base
Susceptance;
% on 100 MVA base
4.4
Circuit constructional detail
Number of cables or conductors per phase
No
Cable or overhead conductor size
mm2
Cable or conductor length
m or km
4.5
User Interconnecting transformers:
5
Required from Users who take supply at the MV terminals of the connecting transformer
For transformers between the Distribution System and the User system, the following data is required;
5.1
Rated Power;
MVA
5.2
Rated Voltage ratio (i.e. primary/secondary/tertiary);
text
5.3
Winding arrangement;
text
5.4
Vector group;
text
5.5
Earthing arrangements
text
5.5
Positive sequence resistance @ nominal tap;
% on MVA rating
5.6
Positive sequence reactance @ nominal tap;
% on MVA rating
5.7
Zero phase sequence reactance;
% on MVA rating
5.8
Tap changer type (e.g. on-load or off-load);
On/Off
The Saudi Arabian Distribution Code
53
Planning Code
5.9
Tap changer range;
5.10
Tap changer step size;
5.11
Impedance value (if not directly earthed);
Ω
User Protection data:
6
Following details relates only to Protection equipment which can trip, inter-trip or close any Connection Point Circuit Breaker or any DSP Circuit
Breaker;
6.1
A full description including estimated settings, for all relays and
Protection systems installed or to be installed on the User system;
Text
6.2
A full description of any auto-reclose facilities installed or to be installed
on the User system, including type and time delays;
Text
Transient Overvoltage assessment data: (Detailed Data)
7
Required ON DSP(s) REQUEST only. Each User is required to submit data with respect to the Connection site as follows (for undertaking
insulation co-ordination studies);
7.1
Busbar layout, including dimensions and geometry together with electrical
parameters of any associated current transformers, Voltage transformers,
wall bushings, and support insulators;
Diagram
7.2
Physical and electrical parameters of lines, cables, transformers, reactors
and shunt compensator equipment Connected at that busbar or by lines
or cables to that busbar (for the purpose of calculating surge
impedances);
Text
7.3
Specification details of equipment Connected directly or by lines and
cables to the busbar including basic insulation levels;
Text
7.4
Characteristics of overvoltage Protection at the busbar and at the
termination of lines and cables Connected at the busbar;
Text
7.5
For any Generating Unit Connected through a transformer, the following
Generating Unit or Production Facility transformer data is required;
three or five limb cores or single phase units to be specified, and
The Saudi Arabian Distribution Code
54
Text
Planning Code
operating peak flux density at nominal Voltage;
The Saudi Arabian Distribution Code
55
Planning Code
Schedule C: Load characteristics data - Demand
User
Dates for which this schedule is correct
To be completed by Users with Demand
The following information is required from each User regarding existing and future Connections for each Connection Point; The annual boxes allow a
User to indicate changes in basic Demand and motor loads and whether the same fluctuation or pulsating load will exist over the following 5 years. If so, it is
unnecessary to complete all boxes or submit a separate schedule for each year of change.
C
Data description
Units
Connection
data
1
Total Load at the Connected site and per phase
kVA
Maximum Demand
kVA
Minimum Reactive Power
kVAr
Equipment type to be Connected
Text
Heating
kW
Lighting
kW
Air Conditioning
kW
Standard
Data
Details required for kW each MV motor drive Connected to the User system
Number and kW
Text and diagrams
2
Standard
Data
Text, diagrams and tables incl. kW
Rated VA
VA
Rated Active Power;
W
The Saudi Arabian Distribution Code
Additional
comments
Data for future years
56
Y1
Y2
Y3
Y4
Y5
Planning Code
Full Load current;
A
Means of starting;
Text
Starting current;
A
Motor torque/speed characteristics;
Text
Drive torque/speed characteristics;
Text
Motor plus drive inertia constant;
Text
(Users with large motors should also complete
Schedule F)
Text
Disturbing Loads greater than 100kW
Details of individual loads which have fluctuating, pulsing or other abnormal characteristics
3
Details of the cyclic variation of Demand (Active
Power and Reactive Power)
Diagrams
Standard
Data
the rates of change of Demand (Active Power and
Reactive Power) both increasing and decreasing
Diagrams
, tables or
text
Detailed
Planning
Data
the shortest repetitive time interval between
fluctuations in Demand (Active Power and Reactive
Power)
Diagrams
, tables or
text
Detailed
Planning
Data
the magnitude of the largest step changes in Demand
(Active Power and Reactive Power), both increasing
and decreasing
kW &
kVAr
Detailed
Planning
Data
Maximum energy demanded per half hour by the
fluctuating load cycle; and steady state residual
Demand (Active Power) occurring between Demand
fluctuations.
kWh
Detailed
Planning
Data
Pulsing (Power electronic) Loads
kW &
kVAr
Standard
Data
The Saudi Arabian Distribution Code
57
Planning Code
The size of the Load,
kW
Standard
Data
the number of pulses,
No.
Detailed
Planning
Data
maximum Voltage notch, and
kV
Detailed
Planning
Data
Harmonic distortion potential (up to the 50th
Harmonic) for a range of realistic conditions;
Table
showing
% against
Hz
Detailed
Planning
Data
Sensitivity of Demand to variations in Voltage and Frequency on the Distribution System at the peak Connection Point Demand (Active
Power)
4
Voltage sensitivity
Frequency sensitivity
kW/V
Detailed
Planning
Data
kVAr/V
kW/Hz
kVAr/Hz
Phase unbalance imposed on the Distribution System
5
Standard
Data
Maximum
%
Average
%
6
Maximum Harmonic content and specific Harmonic
Frequency levels imposed on the Distribution
System;
% in
tabular
format
Standard
Data
7
Details of loads which may cause Demand fluctuations
greater than 1 MW at a Connection Point / Point of
Common Coupling;
Text
Standard
Data
The Saudi Arabian Distribution Code
58
Planning Code
Schedule D1: User Demand profiles
Daily Load
User
Profile for
(day)
Week No
All Users with Demand
This Demand profile should be completed for each year of the 5-year period. Where there is no
change expected, a User may complete the following declaration. [Year 0 refers to the year just
past.]
DSP(s) may request D1 and D2 as part of Connection Data
Declaration - [User name] is unaware of any expected change to this/ these Demand profile(s)
over the 5-year forecast period.
Data description
Y0
Y1
Y2
Y3
Y4
Y5
Update time
Forecast daily Demand profiles in respect of each User system.
1. Day of User maximum Demand (kW) at annual maximum
Demand conditions;
2. Two days notified by DSP
00:00 – 01:00
01:00 – 02:00
02:00 – 03:00
03:00 – 04:00
04:00 – 05:00
05:00 – 06:00
06:00 – 07:00
07:00 – 08:00
08:00 – 09:00
09:00 – 10:00
10:00 – 11:00
11:00 – 12:00
12:00 – 13:00
13:00 – 14:00
14:00 – 15:00
15:00 – 16:00
16:00 – 17:00
17:00 – 18:00
18:00 – 19:00
19:00 – 20:00
The Saudi Arabian Distribution Code
59
End of Jan
Comments
Planning Code
20:00 – 21:00
21:00 – 22:00
22:00 – 23:00
23:00 – 24:00
The Saudi Arabian Distribution Code
60
Planning Code
Schedule D2: User Demand profiles
Weekly and Seasonal Load
User
Year
All Users with Demand
This Demand profile should be completed for each year of the 5-year period. Where there is no
change expected, a User may complete the following declaration. [Year 0 refers to the year just
past.]
WEEKLY
If there is a significant difference in daily load profile for certain days of the week Users must
supply representative profiles for e.g. work days and non-work days.
SEASONAL
Users who expect significant variation in Demand throughout the year should indicate their
expected Maximum Demand and Minimum Demand for each month and if certain periods have
different daily profiles these should be supplied.
Maximum Demand kVA
January
February
March
April
May
June
July
August
September
October
November
December
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61
Minimum Demand kVA
Planning Code
Schedule D3: Generating Unit Output usable and
Controllable Demand Profiles
Daily Output usable and/or Controllable Demand
User
Profile for
(day)
Site
Week No
Generating Unit / Controllable Demand
identifier
All Users with Generating Units and all Users with Controllable Demand
This Output usable/Controllable Demand profile should be completed for each year of the 5year period. Where there is no change expected, a User may complete the following declaration.
[Year 0 refers to the year just past.]
DSP(s) may request D3 and D4 as part of Connection Data
Declaration - [User name] is unaware of any expected change to this/ these Output
usable/Controllable Demand profile(s) over the 5-year forecast period.
Data description
Y0
Y1
Y2
Y3
Y4
Y5
Update
time
Comments
Forecast daily Output usable/Controllable Demand profiles in respect of each Generating Unit
and/or Controllable Demand.
1. Day of Generating Unit maximum Output usable (kW) at
annual maximum Demand conditions;
End of Jan
2. Two days notified by DSP
And/Or:
1. Day of User maximum Demand (kW) at annual maximum
Demand conditions;
2. Two days notified by DSP
1.
00:00 – 01:00
01:00 – 02:00
02:00 – 03:00
03:00 – 04:00
04:00 – 05:00
05:00 – 06:00
06:00 – 07:00
07:00 – 08:00
08:00 – 09:00
09:00 – 10:00
10:00 – 11:00
11:00 – 12:00
The Saudi Arabian Distribution Code
62
End of Jan
Planning Code
12:00 – 13:00
13:00 – 14:00
14:00 – 15:00
15:00 – 16:00
16:00 – 17:00
17:00 – 18:00
18:00 – 19:00
19:00 – 20:00
20:00 – 21:00
21:00 – 22:00
22:00 – 23:00
23:00 – 24:00
The Saudi Arabian Distribution Code
63
Planning Code
Schedule D4: Generating Unit Output Available and
Controllable Demand Profiles
Weekly and Seasonal Load
User
Year
All Users with Generating Units
This Output usable profile should be completed for each year of the 5-year period. Where there is no
change expected, a User may complete the following declaration. [Year 0 refers to the year just past.]
WEEKLY
If there is a significant difference in daily profile for certain days of the week Users must supply
representative profiles for e.g. work days and non-work days.
SEASONAL
Users who expect significant variation in Output usable throughout the year should indicate their
expected maximum Output and minimum Output for each month and if certain periods have different
daily profiles these should be supplied.
All Users with Controllable Demand
This Controllable Demand profile should be completed for each year of the 5-year period. Where
there is no change expected, a User may complete the following declaration. [Year 0 refers to the
year just past.]
WEEKLY
If there is a significant difference in daily profile for certain days of the week Users must supply
representative profiles for e.g. work days and non-work days.
SEASONAL
Users who expect significant variation in Controllable Demand throughout the year should indicate
their expected maximum Demand and minimum Demand for each month and if certain periods have
different daily profiles these should be supplied.
Maximum Output usable or Maximum
Controllable Demand kVA
January
February
March
April
May
June
July
August
September
October
November
December
The Saudi Arabian Distribution Code
64
Minimum Output usable or Minimum
Controllable Demand kVA
Planning Code
Schedule E: Connection Point
User
Schedule required from each User with Demand
E
Data description
Units
Y0
Y1
Y2
Y3
Y4
Y5
Update
time
Forecast Demand and Power Factor related to each Connection Point
1
To be completed by all Users with Demand; Users with Demand and Generating Units should report their Demand Power Factor here.
1.1
Annual peak hour User Demand at
annual maximum Demand conditions;
MW
End of Jan
Power
Factor
Demand Transfer Capability
2
To be reported by Users who have agreed with the DSP that Demand may be fed by alternative Connection Point (s)
2.1
Name of the alternative Connection
Point (s);
2.2
Demand transferred;
2.3
Transfer arrangement (e.g. manual or
automatic);
2.4
Time / mechanism to effect transfer;
kW
kVAr
hours
Controllable Demand
3
To be reported by Users who have an arrangement whereby at least part of their Demand may be controlled in response to some signal
3.1
Amount of Demand that may be
controlled
kW
3.2
Contractual constraints on
Text
The Saudi Arabian Distribution Code
65
Planning Code
Controllable Demand
3.3
Arrangements for control
The Saudi Arabian Distribution Code
Text
66
Planning Code
Schedule F: Fault infeed data
User
Name of Connection Point:
Information correct for
(Date)
The following information is required from each User whose User system contains Generating Unit(s) and/or motor loads capable of providing a
contribution to short circuit current. (In general, type B Asynchronous Generating Units and DC drives do not make a short circuit contribution). If the
information changes over time separate schedules should be supplied.
The highest short-circuit Infeed to the Distribution System from a User system at a Connection Point. The User shall provide a calculation sheet showing
the fault current available from the Generating Units due to a metallic three-phase short circuit at the main incoming Circuit Breaker when all the Generating
Units are operating. Account should be taken of any large motors in the installation (ref: SASO IEC60909 standards)
F
Data description
Units
Connection Data
All Voltages
Symmetrical three-phase short circuit current infeed
1
At instant of fault
kA
After sub-transient fault current contribution has
substantially decayed;
kA
Zero sequence source impedance values as seen from
the Connection Point consistent with the maximum
infeed above
2
3
All Voltages
Resistance (R)
% on 100
MVA
Reactance (X)
% on 100
MVA
Positive sequence X/R ratio at instance of fault;
The Saudi Arabian Distribution Code
All Voltages
67
Y1
Y2
Y3
Y4
Y5
Planning Code
Schedule G: Generating Units >100kW
User
Location
Data related to all Power Production Connection sites
The following data are required from each User with existing or proposed Generating Units
G
Data description
Units
Connection
Data
1
Location and Registered Capacity;
Text & MW
All Voltages
2
Name plate data for all equipment
Text
All Voltages
3
Diagram showing arrangement of Generating Units in facility &
how Protection is organised;
Diagram
All Voltages
4
Maximum phase imbalance on start-up and normal running
%
All Voltages
Y1
Y2
Y3
Y4
Y5
The following data, if requested by the DSP, are to be supplied in separate tables for each year for Generating Units greater than 2MW Connected to parts
of the Distribution System not permanently interconnected with the Transmission System.
[Users supplying such data to the TSP under the Grid Code need not resubmit this data.]
5
Available capacity on a monthly basis (or the periods when
quantities of generation will be unavailable.) >200kW
kW
6
Requirement for top-up supplies or stand-by supplies
kW
The Saudi Arabian Distribution Code
68
If requested by
DSP(s)
Planning Code
User
Production Facility name / Location
All Generating Units
The following details are required from each User with existing or proposed Generating Units of all sizes, Connected, or to be Connected, to the
Distribution System. U1 – U2 allows up to two Generating Units to be identified on a single return. Additional forms can then be completed.
General
Units
Connection Data
7
Type of Generating Unit, Synchronous;
Asynchronous - Type A – Induction or Type B
with converters)
Text &
diagram
Standard Data
8
Type of Prime Mover
Text
Standard Data
9
Arrangement diagram e.g. Asynchronous
Generating Unit
Text &
diagram
Standard Data
10
Means of Connection & disconnection to be
employed
Text and
diagram
Standard Data
11
Rated terminal Voltage
kV
Standard Data
12
Registered Capacity;
kW
Standard Data
13
Rated Active Power;
kW
Standard Data
14
Rated VA;
kVA
Standard Data
15
Maximum Active Power sent out
kVA
Standard Data
16
Reactive Power requirements
kVAr
Standard Data
17
System constrained capacity
MW
Detailed Planning Data
18
Minimum generation;
MW
Detailed Planning Data
19
Active Power available in excess of Registered
MW
Detailed Planning Data
The Saudi Arabian Distribution Code
69
U1
U2
Comment
Planning Code
Capacity;
20
Size of significant Demand for energy on start-up
or following faults and duration;
21
Expected operating regime(s);
The Saudi Arabian Distribution Code
MW
Standard Data
If requested by the DSP
70
Planning Code
Schedule H - Synchronous generators
User
Location
Power Production Facility name
Synchronous Generating Units connecting to the Distribution System are of various types and sizes.
The following data tables require less data than for Transmission Connected Generating Units, but contain sufficient data to allow modelling of load flow,
Fault Level and transient behaviour of the Distribution System with the largest sized Generating Units likely to be Connected to that system.
For convenience, the data requirements are divided by the size of the Generating Unit, however the DSP may request any data listed or other reasonable
technical information regarding its Production Facility or Generating Units from any Power Producer. Users should note that the number and size of
Generating Units and location on the Distribution System are factors in determining the impact of Generating Units on system performance.
Power Producers shall also provide details of any other significant ancillary equipment as part of their Demand schedules B-F including full details of
Disturbing Loads.
H
Data description
Units
1
Generator Performance Chart at stator
terminals;
Chart
2
Short circuit ratio;
3
Generating Unit inertia constant;
Size requirement /
Connection Data
>200kVA
Detailed Planning Data
Standard Data
MWs/
>50kVA
MVA
Detailed Planning Data
Generator Efficiency
4
Fuel type
text
On Request
5
Generating Unit overall efficiency
(excluding Gen Transformer)
%
On Request
Impedances for generators
The Saudi Arabian Distribution Code
>50kVA
71
U1
U2
Comment
Planning Code
Minimum Connected impedance of
Generator and Generator Transformer;
% on MVA
generator
base
Earthing arrangements for Generating
Unit and Generator transformer
Diagram
and text
7
Details of precautions to be taken to
ensure the continuance of safe conditions
if any earthed neutral point of the Power
Producer’s system operated at Medium
Voltage become disconnected from Earth.
Text &
Diagram
Detailed Planning Data
8
Direct axis Synchronous reactance;
% on MVA
generator
base
Detailed Planning Data
8
Direct axis transient reactance;
% on MVA
generator
base
Detailed Planning Data
9
Direct axis sub-transient; reactance;
% on MVA
generator
base
Detailed Planning Data
10
Quadrature axis Synchronous reactance;
% on MVA
generator
base
Detailed Planning Data
11
Quadrature axis sub-transient reactance;
% on MVA
generator
base
Detailed Planning Data
12
Stator leakage reactance;
% on MVA
generator
base
Detailed Planning Data
13
Armature winding direct-current
resistance;
% on MVA
generator
Detailed Planning Data
6
The Saudi Arabian Distribution Code
Standard Data
72
Planning Code
base
Time constants
>50kVA
14
Direct axis short-circuit transient time
constant;
s
Detailed Planning Data
15
Direct axis short-circuit sub-transient time
constant;
s
Detailed Planning Data
16
Quadrature axis short-circuit sub-transient
time constant;
s
Detailed Planning Data
17
Stator time constant;
s
Detailed Planning Data
Generator transformer:
18
Rated VA;
MVA
Standard Data
19
Rated Voltage ratio;
Text
Standard Data
20
Winding arrangement;
Diagram
Standard Data
21
Vector group;
Text
Standard Data
22
Positive sequence resistance;
% on MVA
Standard Data
23
Positive sequence reactance;
% on MVA
Standard Data
24
Zero phase sequence reactance at:
% on MVA
Standard Data
25
Tap changer range;
±%
Detailed Planning Data
26
Tap changer step size;
±%
Detailed Planning Data
27
Tap changer type; (i.e. on-load or offcircuit)
On / Off
Detailed Planning Data
28
Impulse withstand level
kV
Detailed Planning Data
Voltage Control Method - Excitation control system
The Saudi Arabian Distribution Code
>200kVA
73
Planning Code
parameters:
29
Exciter category (e.g. rotating or static);
Text
Detailed Planning Data
30
Details of excitation system (including over
and under excitation limiters) described in
block diagram showing transfer functions
of individual elements – all parameters
needed;
Diagram
Detailed Planning Data
31
Power system stabiliser fitted?
32
AGC whether fitted or not and model
details and settings ≥2MW
Yes
/No
Detailed Planning Data
YES/NO
Model
settings
Detailed Planning Data
Diagram
Detailed Planning Data
Governor parameters
33
Governor system block diagram showing
transfer function of individual elements and
settings range, interval and Dead Bands;
≥2MW
Interface Arrangements – Synchronous Production Facilities - capability
34
Arrangements for Synchronising with the
Distribution System Voltage
Text
Standard Data
Standard Data
Black Start
35
Whether Black Start capability exist for
each Generating Unit or the Power
Production Facility
Yes / No
36
Details of arrangements
Text &
The Saudi Arabian Distribution Code
74
Planning Code
diagram
37
Limitations on start-up process
38
Black Start agreement with TSP
The Saudi Arabian Distribution Code
Yes / No
75
Planning Code
Schedule I - Asynchronous Generators
User
Power Production Facility name
Location
Synchronous Generating Units connecting to the Distribution System are of various types and sizes.
The following data tables require sufficient data to allow modelling of load flow, Fault Level and transient behaviour of the Distribution System with the
largest sized Synchronous Generating Units likely to be Connected to that System.
For convenience, the data requirements are divided by the size of the Generating Unit, however the DSP may request any data listed or other reasonable
technical information regarding its Production Facility or Generating Units from any Power Producer.
Users with a generator transformer separate from the Asynchronous Generating Unit or a site transformer connecting several Generating Units to the
Distribution System shall additionally supply details of transformers as follows:
Power Producers shall also:

provide details of any other significant ancillary equipment as part of their Demand schedules B-F including full details of Disturbing Loads.

State requirements for “top-up supplies” and/or “standby supplies”.
I
Generator transformer:
Units
Size Requirement /
Connection Data
1
Rated VA;
MVA
Standard Data
2
Rated Voltage ratio;
Text
Standard Data
3
Winding arrangement;
Diagram
Standard Data
4
Vector group;
Text
Standard Data
5
Positive sequence resistance;
% on MVA
Standard Data
6
Positive sequence reactance;
% on MVA
Standard Data
7
Zero phase sequence reactance at:
% on MVA
Standard Data
8
Tap changer range;
±%
Standard Data
9
Tap changer step size;
±%
Standard Data
The Saudi Arabian Distribution Code
76
U1
U2
Comment
Planning Code
10
11
Standard Data
Tap changer type;
On/
(i.e. on-load or off-circuit);
Off
Impulse withstand level
kV
Detailed Planning
Data
Units
Size (MVA)
Asynchronous Generating Units
12
Capability curve showing Reactive Power
Output range against Active Power
Table or diagram
Standard Data
13
Arrangements for Voltage control,
Reactive Power control and Power
Factor control
Text and diagram
Standard Data
14
Low Voltage Ride Through capability
Diagram of
minimum Voltage
v time and on DSP
request a study.
Standard Data
15
Harmonic content imposed by each
Generating Unit and the wind powered
Generating Unit
Tables of %
Harmonic at each
Hz
Detailed Planning
Data
16
Maximum current unbalance during
normal and fault Operation
A
Detailed Planning
Data
17
Details of power conditioning equipment
Text & diagram
Detailed Planning
Data
18
Details of islanding Protection
Text
Detailed Planning
Data
19
Parameters similar to above, sufficient to
populate manufacturers’ models
Tables
Detailed Planning
Data
20
Regime of generation e.g. solar hours only
The Saudi Arabian Distribution Code
77
Connection Data
U1
U2
Comment
Planning Code
21
An extended period dynamics model
showing timed response to system
Voltage
Block diagram or
assembled model
Detailed Planning
Data
Wind Turbine Generating Units
22
Turbine /energy convertor types
Text
Standard Data
23
No of turbines
Number
Standard Data
24
Layout of turbines
Map diagram
Standard Data
25
Power Output / wind speed for the wind
powered Generating Unit
MWh/km
Standard Data
26
Maximum Output for each wind turbine
generator and Power Output /wind speed
MWh/km
Standard Data
27
On request – a model or block diagram in
approved form, showing Output in load
flow and dynamics studies and accounting
for incident wind shall be provided for
Wind Power Generating Units of
significant size having regard to their
environment as determined by the DSP.
The model may be used to determine
compliance of the design and compare as
built performance.
Model or block
diagram
Detailed Planning
Data
Solar Generating Units
28
Energy conversion process:
29
Thermal or PV
Text
Standard Data
30
Size, numbers, technical data and
electrical arrangement of PV invertors
kVA
Standard Data
31
Further details of the process
Text
Standard Data
The Saudi Arabian Distribution Code
78
Planning Code
The arrangement and capacity of Solar
Generating Units within the Solar Power
Production Facility including size, number,
surface and orientation of PV panels
No.
Standard Data
MW
Standard Data
Map diagram
Standard Data
33
Rate of increase of Asynchronous
Generating Unit’s Output for Frequency
deviations under a range of percentage of
maximum incident light conditions;
MW/s or MW/MIN
Detailed Planning
Data
34
Solar Generating Units and Solar Power
Production Facility model
Block diagram and
assembled model
Detailed Planning
Data
35
In approved form, a model showing
Output in load flow and dynamics studies
and accounting incident light, for Solar
Generating Units of significant size
having regard to their environment as
determined by the DSP
32
The Saudi Arabian Distribution Code
Detailed Planning
Data
79
Planning Code
Schedule J – Energy storage units
User
Power Production Facility name
Location
Note these Unit could be based upon Synchronous or Asynchronous technology – the appropriate Demand and Generation Schedules shall also be
completed.
1
The arrangement of Energy Storage units
within a facility
Standard Data
2
The maximum charging current for the facility
Standard Data
3
The maximum charging current of each
Energy Storage unit within the facility
Standard Data
4
The maximum discharge current of each
Generating Unit within the facility
Standard Data
5
The maximum ramp rate of the facility up; and
down (including also when charging from
charging to discharging and discharging to
charging
6
a model in approved form, capable of use in
load flow and dynamics studies, shall be
provided for Energy Storage units of
significant size having regard to their
environment as determined by the DSP)
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kW/s
Detailed
Planning Data
On request
80
Planning Code
Schedule K – Outage Schedules
The DNO will seek this information at appropriate times throughout the year. Insert new outages, delete those that have
been cancelled, and update those that have changed. Please provide data for years 1, 2 and 3 (year 0 is the year that
has just finished).
User
User Facility
name
Equipment
Description
Location
Outage dates
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Work content (e.g. maintenance/replacement/testing) et, and any
other relevant issues, e.g. risk of trip etc
81
Emergency return to service
times (hrs)
Planning Code
Appendix C – Security of Supply Standards
Class
Group Demand
First circuit outage
Interpretation
A
<= 2 MVA
Restore full group Demand in
repair time
N
Restore Group Demand minus 2
MVA within 3 hours
B
2 <= 12 MVA
AND
N-1 (manual switched
alternatives)
Restore group Demand in repair
time
C
12 MVA <= 60
MVA
Restore Group Demand in 15
minutes
N-1 (auto or remote
switch alternatives)
Group Demand - The maximum forecast demand in any year on a section
of the network that is being considered for Security of Supply Standard
compliance.
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Connection Conditions
CONNECTION CONDITIONS
CONTENTS
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Connection Conditions
The process for establishing a new Connection or the modification of an
existing Connection to the Distribution System, and the data needed
are set down in the PC which specifies the information to be provided by
Users with Demand to ensure that adequate provision can be made by
DSP(s) for new Connections or increases in existing load. The
Connection Conditions also apply to Power Producers who operate
Generating Units in parallel with the Distribution System, where a
Connection, or modified Connection is required. The process for
establishing or modifying a Connection is further explained in the ESPM.
Generating Units which cannot be operated in parallel with the
Distribution System are not subject to the requirements of the
Distribution Code.
The Connection Conditions (CC)are applicable to all Voltage levels
covered by the Distribution Code and specify minimum technical, design,
operational criteria and standards to be complied with by:
Users Plant and apparatus;
the method of Connection to the Distribution System;
the technical arrangements at the Ownership Boundary between
the Distribution System and the User’s installation.
In order to maintain 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 Distribution System.
This CC sets out the minimum technical, design and operational criteria,
which must be complied with by DSPs. These criteria are required for the
Protection of the Distribution System and Users’ Plant and to enable
the DSPs to comply with their licences.
If a User considers that it is unable to meet any of the conditions, they
should seek derogation from the WERA in accordance with the provisions
of GC.12.
Each User has, or will have a Connection Agreement with the DSP. The
Connection Agreement contains details specific to the User’s
Connection to, and use of, the Distribution System. The Connection
Agreement requires the User and the DSP to comply with the terms of the
Distribution Code. On occasion, site specific conditions require
alternative provisions to the more general provisions in the Connection
Conditions. Certain parts of the Connection Conditions make provision
for this in line with the hierarchy of the documents as stated in GC.4
The objectives of the Connection Conditions are to ensure:
no new or modified Connection will impose unacceptable effects on
the Distribution System and / or other Users;
By specifying minimum technical, design and operational criteria, the
basic rules for Connection between the Distribution System and a
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Connection Conditions
User system are similar for all Users within an equivalent category.
In this way, the Connection Conditions enable DSP(s) to comply
with the Sector Law and License Obligations in a non-discriminatory
way.
The integrity of the Distribution System and the security and quality
of supply to existing Users shall not be allowed to fall below
minimum standards as a result of Generating Units operating in
parallel with the Distribution System. Conditions for Connection
and Operation shall guarantee the safety of members of the general
public, personnel and distribution equipment.
In addition to DSPs, the Connection Conditions apply to the following
Users:
Demand Customers of all types;
Power Producers whose Generating Units are Connected to the
Distribution System at any Distribution Voltage;
Licensed Retailers; and
Licensed Traders.
All applicants seeking a Demand Connection to the Distribution System
should in the first instance seek the Connection by approaching the
relevant DSP.
PC.8 details the steps which a User normally takes in conjunction with the
DSP to determine the opportunity for Connection to the Distribution
System.
PC.8.2 states that procedures relating to application for Connection to the
Distribution System are contained in the ESPM as prepared by DSP(s)
and approved by WERA.
The User shall initiate discussions at a sufficiently early stage in design to
allow the DSP to examine the impact of the User’s Demand or Generating
Unit(s) on the Distribution System.
The DSP may refuse permission for the Connection of a new Demand or
Generating Unit at a point on the Distribution System or require revision
to design or technical parameters of the Plant and apparatus or
Generating Unit, or impose certain restrictions in order to ensure that
security and quality of supply standards as specified in PC.4 are maintained.
In such instances, the DSP shall provide sufficient supporting information
to justify the refusal or the required revisions.
Information needed for an offer of Connection
The exchange of information needed,
For the DSP to perform power system load flow, dynamic and other
studies or analyses; and
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Connection Conditions
to enable Users to design their systems,
is stated in the PC.6.
There is no requirement for Minor Customer’Minor Customers to
participate in the connection information exchange of this Distribution
Code. Minor Customer’Minor Customers shall comply with the
requirements of the ESPM sets down timeframes for stages of the
Connection process. Copies of this manual are available on request from
the DSP.
The full list of information required from Users or potential Users is
identified in the data schedules in Appendix B of this PC.
Data Schedules for Users
Connection information in the data schedules A to I in Appendix B is
identified and required unless provision of part or all the data is waived by
the DSP. Schedules A - I are relevant to Users of each type, so:
schedule A is required by all Users;
schedules B to E are to be completed by Users with Demand;
schedule F is to be completed by Users with Demand and Power
Producers.
schedules G to I are to be completed by Power Producers.
Schedule H refers to Power Producers with Synchronous
Generating Units and schedule I to Power Producers with
Asynchronous Generating Units.
PC.6.5 to PC.6.12 explain how Users, including Users with Complex
systems, are to report their data for the purposes of Connection and
annually thereafter.
Information needed prior to completion of the Connection
Prior to the completion date agreed in the Connection Agreement, the
following information is to be submitted by the User:
statement that the User’s installation complies with the
requirements of SADC;
updated PC data with any estimated values assumed for planning
purposes confirmed or, where practical, replaced by validated
actual values and updated forecasts for items such as Demand;
a Protection philosophy document showing how Plant is protected
and how:
a.
selectivity is arranged to avoid large loss of power infeed;
and
b.
details of Protection settings agreed.
a full description including estimated settings, for all relays and
Protection systems installed or to be installed on a Generating
Unit, Generating Unit transformer, transformer directly linking the
User’s installation to the Distribution System and/or associated
Connection;
the most probable fault clearance time for electrical faults on any
part of a User system Connected to the Distribution System;
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Connection Conditions
copies of all Safety Rules and Local Safety Instructions applicable
at Users’ sites which shall be used at the DSP/User interface;
information to enable the DSP to prepare Site Responsibility
Schedules;
an operation diagram for all Plant on the User side of the
Connection Point;
the proposed name of the User site (which shall not be the same
as, or confusingly similar to, the name of any of the DSP’s sites or
of any other User site);
a list of Safety Coordinators in the case of Complex or MV
installations;
a list of the contact details for joint system incidents at which senior
management representatives nominated for the purpose can be
contacted and confirmation that they are fully authorized to make
binding decisions on behalf of the User;
a list of managers who have been duly authorized to sign the Site
Responsibility Schedule on behalf of the User;
information to enable the preparation of Site Common Drawings;
confirmation of and communication or SCADA interface
arrangements for instruction, confirmation of instruction and
information including the list of signals, and that these signals are
formatted as required by the DSP and, as appropriate, the SSECC;
and
Metering System Registration Data.
Ownership Boundary
The point or points at which supply is given or taken between the
Distribution System and the User’s installation shall be agreed in the
Connection Agreement between the DSP and the User.
For Low Voltage supplies the DSP’s responsibility extends up to the
Customer’s Connection Point, which is normally at the DSP’s main
Circuit Breaker.
For Medium Voltage supplies, the Ownership Boundary shall be subject
to specific agreement between the parties. Changes in the Ownership
Boundary arrangements proposed by either party shall be agreed in
advance and shall be recorded in the Connection Agreement.
All equipment at the Ownership Boundary shall meet the design
principles contained in CC.6. Connections to the Distribution System
shall incorporate a means of disconnection of the User’s installation by
the DSP.
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Connection Conditions
Basic technical requirements for all Connections
Overall requirements
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.
The specific arrangements for Connection, including substation layout
requirements, User equipment, and metering are set out in the
Distribution Code. Users must comply with those provisions of both
documents which are relevant to their installations.
Compliance Monitoring of Technical Requirements and Performance
Before connecting any User to the Distribution System, it will be
necessary for the DSP to be reasonably satisfied that the User’s system
complies with the requirements of the Distribution Code. An statement of
compliance is required, in PC.6.6 prior to Connection. This statement is to be
in a form set down by the DSP.
Compliance for all Generating Units
For all Generating Units, an equipment certificate and Detailed Planning
Data prepared by the equipment supplier or validated by a competent
person shall be provided for compliance verification.
Compliance for Generating Units with a Registered Capacity of 2MW or
Greater
For 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.
Compliance of Asynchronous Generating Units
For some types of Asynchronous Generating Units, it may not be
possible initially to test certain requirements of the facility e.g. Low voltage
ride through. Where the Asynchronous Generating Unit is otherwise
compliant, it shall receive a 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 Asynchronous Generating
Unit fails to achieve the performance standard set down in this
Distribution Code, a Final Connection Certificate will be issued.
Method of Connection to the Distribution System
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 the DSP and the User. The network
configuration at the Connection Point may take a number of forms
suitable to the nature of the User’s installation and the local network
arrangements.
During the application for a Connection process, the DSP shall, in
consultation with the User, specify the Voltage level to which a User will be
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Connection Conditions
Connected in accordance with normal practice for the User installation and
the local network characteristics.
Generally, the Voltage level will be the minimum nominal Voltage in
standard use on the system, assessed against:
satisfactory Operation of the installation;
Isolation of disturbance from other Customers;
lifecycle costs; and
cost of Connection.
The DSP 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
or Generating Units.
Connection Standards
From the time that this Distribution Code is 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.
For equipment approved to be Connected to the Distribution System
before issuing this Distribution Code, that is compliant with other
standards such as ANSI, ASTM, IEEE, UL, EN, DIN, BS, … etc , those
relevant standards can be applied for a further period, on 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 DSPs.
In case of any conflict between SASO standards and the other standards,
SASO or equivalent IEC standards shall be applied.
If there are no relevant SASO standards or equivalent IEC standards
available, and/ or if the DSP considers it necessary, the DSP may notify
the Users that supplemental specifications and/or standards shall be
complied with, in which case the User’s Plant and apparatus shall so
comply.
Tolerance of System Conditions
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 the Voltage and short-circuit rating and the insulation level
as shown in PC.4.2.2.1, CC.6.2.10 and CC.6.2.11 at the Connection
Point. The DSP may require certification that the equipment has been
designed and installed in a satisfactory manner. The DSP may also seek
evidence that the equipment has been tested for conformity with the
standards.
For Users Connected at Low Voltage, installations shall comply with the
standards as in CC.6.2.10 and CC.6.2.11.2. Users complying with these
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Connection Conditions
rules and regulations shall be deemed to comply with the requirements of
the Distribution Code as regards design and safety. The DSP may seek
evidence that the equipment has been tested for compliance with
standards.
Protection and Control Requirements
Protection conditions and requirements are to protect the Distribution
System. The User is responsible for Protection of its personnel and
equipment.
Faults on the User System shall not disturb the Distribution System
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 this paragraph.
Minimum Protection Requirements
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:
phase over current Protection;
Earth fault Protection (suited to the local supply system);
line differential Protection (If deemed necessary and designed /
installed as agreed between the DSP and the User);
inter-tripping; and
Others specific to the installation.
Faults on the Distribution System shall not damage the User System
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 and procedures applicable to the particular network
to which a Connection is to be made, and ensure that Protection
installed is compatible with that used by the DSP. The adequacy of the
Protection installed by the User is the User’s responsibility.
Protection Co-ordination at the Ownership Boundary
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, specifications and any additional requirements, as specified by
the DSP at the time of application. In particular:
the maximum fault clearance times (from fault current inception to
Circuit Breaker arc extinction) shall be set out in accordance with
each Connection Agreement and within the limits established by
the DSP for primary Protection in accordance with the Protection
and equipment short-circuit rating policy adopted for the MV
Distribution System.
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Connection Conditions
The DSP shall take account of the type of Protection, system
stability and system safety and the effects on the Transmission
System. The probability that these times will be exceeded for any
given fault must be less than 1%;
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/reenergization of the power supply. Dead times are typically 0.3s, 1s
and 10s on parts of the Distribution System designed to be
operated above 1kV but 3s and 60s on 38kV systems. However,
these are general guidelines and the DSP shall communicate the
necessary information formally to the User and shall update the User
as often as such information is changed; and
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 on the
Distribution System.
Interface Circuit Breakers
Where interface Circuit Breakers are used, they shall be fitted with
current transformers and protective relays of a type acceptable to the DSP.
These current transformers and protective relays shall have three-phase
over-current elements and one Earth-fault element and shall have timecurrent characteristics complying with standard types A, S and C of SASO
/ IEC 60255 and shall be in compliance with any other terms of the DSP’s
specification and requirements as referenced in the User’s Connection
Agreement.
The DSP shall provide maximum permissible Protection settings while
ensuring upstream coordination and respecting system stability and safety
limits. It shall be Users responsibility to refer to the DSP Protection
Settings and ensure selectivity and coordination of the Users
downstream equipment. Distribution Protection aims to minimize the
impact of faults including Voltage dip duration and must not be adversely
affected by Customer’s Protection limitations.
Content of the User’s Protection philosophy statement
In order to ensure satisfactory Operation of the Distribution System,
Protection systems, operating times, discrimination, and sensitivity at the
Ownership Boundary stated in the User’s Protection philosophy
statement shall be shown to provide adequate Protection co-ordination
with the DSP’s interface settings and such philosophy statement shall be
agreed between the DSP and the User during the application for
Connection process, and may be reviewed from time to time by the DSP;
Provision Against the Failure of a Circuit Breaker
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, Backup Protection shall normally be provided by the
Operation of other Circuit Breakers or equipment having a similar
function;
Limitation of the Fault Current Infeed
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Connection Conditions
Unless the DSP advises otherwise, the use of Protection and associated
equipment to limit the fault current infeed 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 the DSP to operate outside its short-circuit
rating.
Commissioning of Protection relays
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, the DSP may wish to witness these tests and it shall be the
responsibility of the User to ensure that sufficient notice is given to the DSP
in such cases. Users shall ensure that the Protection settings remain
below the maximum permitted levels. This may require regular testing of
the relays.
Interface Protection settings and settings affecting generation Operation
shall not be changed without the permission of the DSP.
Earthing Requirements
The DSP shall advise on the method of Earthing of the Distribution
System as stated in PC.4.2.5. The specification of associated User
equipment shall be appropriate to the Voltages that will be imposed on the
equipment as a result of the method of Earthing.
The arrangements for connecting the User’s installation with Earth shall be
designed to comply with relevant international (IEC) and national (SASO)
standards.
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.
Earthing of the part of the User’s installation that is Connected to the
Distribution System shall comply with the following requirements:
Bonding of LV neutral and MV Earths
LV neutral Earthing and any earths associated with MV equipment /
system (e.g. MV metalwork, cable screen, etc.) shall be kept bonded.
Earth Resistance
The recommended resistance limits for different installations should be as
shown in Table 9 below.
Installation
Resistance
System Earthing
≤ 5 ohms
All distribution sub-station
≤ 5 ohms
Surge arrestors
≤ 5 ohms
LV Distribution panel
≤ 10 ohms
Table 9: Resistance limits for different installations
Earthing of LV metering installations
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Connection Conditions
The User shall provide Earthing at its interface. The User shall bring the
Earth wire to the Earthing terminals provided in the Meter box. The
User’s Earth wire shall be Connected to the Earthing terminal inside the
Meter box. The Earthing terminal shall be short linked with the neutral.
Up to four Meters may be Connected to one Earth rod. In case of
additional Meters at the premises, additional Earth rods shall be provided.
Ground mounted MV equipment
The equipment covered is RMUs, MV switches etc, when separated from
transformer and User’s indoor switchgear. All metal work shall be bonded
together and to the substation metalwork Earthing system. Each
continuous piece of metal that could form part of the path of a ground fault
current shall be bonded to its neighbours so that continuity of Earthing
circuit does not depend on mechanical Connection between components.
Requirements in relation to Voltage Regulation and Control
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 the DSP if requested by the User.
Requirements to tolerate Short-Circuit Levels
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 10 below. The DSP shall take into account the contribution
to Fault Level of the User’s Connected system and apparatus in the design
of its system.
Connection Voltage
Size of load (kVA)
Short circuit level (RMS
Symmetrical (kA))
≤152
21
≥152
45
≤500
20
≥500
30
≤500
20
≥500
30
13.8 kV
All
21
33 kV
All
25
69 kV
All
31.5
220 / 127 V
380 / 200 V
400 / 230 V
Table 10: Short circuit ratings
Requirements for Users’ equipment to meet insulation levels
Medium Voltage levels
Unless otherwise specified in the User’s Connection Agreement, the
basic insulation level (BIL) and power Frequency withstand Voltage for
medium system Voltages are as tabulated below in Table 11:
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Altitude above mean sea levels
System nominal Voltage (kV
RMS)
Up to 1,000 metres
Above 1,000 metres
BIL (kV peak)
325
350
Power Frequency withstand
Voltage (kV RMS)
140
160
BIL (kV peak)
170
200
Power Frequency withstand
Voltage (kV RMS)
70
80 / 75
BIL (kV peak)
95
110
Power Frequency withstand
Voltage (kV RMS)
38
50 / 45
Table 11: Basic Insulation levels for Medium Voltage apparatus
Note: The dry/wet power Frequency withstand Voltages are dry for one
minute and wet for ten seconds.
Low Voltage levels
Unless otherwise specified in the User’s Connection Agreement, the BIL
and power Frequency withstand Voltage for low system Voltages are as
tabulated below in Table 12:
System nominal
Voltage (V)
Power Frequency withstand
Voltage (kV RMS)
BIL (kV peak)
Equipment
Panel wiring
3
2
277 / 480
230 / 400
6
220 / 380
127 / 220
Table 12: Basic Insulation levels for Low Voltage apparatus
Requirement to assess Capacitive and Inductive Effects
The User shall, when applying to make a Connection, provide the DSP
with information as detailed in PC.6 . Details shall be provided of any
capacitor banks or reactors Connected at MV, which could affect the
Distribution System or which it is proposed to Connect . When requested
by the DSP, details shall also be provided of distributed circuit capacitance
and inductance. Sufficient detail is required for the following:
to verify that controlling equipment of the Distribution System is
suitably rated;
to show that the performance of the Distribution System will not be
impaired.
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Connection Conditions
Users to comply Quality of Supply Requirements
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 Voltage ranges and disturbances at the
levels that can be expected on the Distribution System as stated in
PC.4.2.2.
The Distribution System shall comply with the emission limits, which are
set out in PC.4.2.3 (Harmonics) and PC.4.2.4 (Phase unbalance).
User’s power quality requirement
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 SASO IEC.61000-3-6;
Voltage fluctuations shall be within the limits defined in the most
recent approved version of SASO IEC 61000-3-7;
phase unbalance of currents shall not exceed 1% for Users
Connected at MV;
Users with transformers which Connect their installation to the
Distribution System shall ensure that the DSP’s requirements for
Voltage stability of the Distribution System are complied with.
Special conditions for Power Producers are presented in PC.6.10.
Metering and Telemetry
The User may be required to provide such Voltage, current, Frequency,
Active Power and Reactive Power pulses as are considered necessary
by the DSP to ensure adequate system monitoring. Details will be specified
in the User’s Connection Agreement.
Centrally Dispatched Generating Units, shall provide signals to the TSP
as required by the Saudi Arabian Grid Code (SAGC).
If it is agreed between the parties that the DSP shall control the switchgear
on the User’s system, the DSP shall install the necessary tele control
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.
Metering principles applying to certain Users Connected to the
Distribution System shall be specified in User’s Connection
Agreements.
Specific metering arrangements depend on the load type, size and nature
of the installations being Connected and are specified in the Metering
Code forming part of this Distribution Code.
In the absence of agreement between the parties to the contrary,
construction, commissioning, control, Operation and maintenance
responsibilities follow ownership.
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Connection Conditions
The following requirements apply to any site where the equipment is
deemed by the User or the DSP to be of Complex arrangement and to all
sites with equipment operating at Medium Voltage and above.
Responsibilities for safety
Any User entering and working on its Plant on the DSP’s site will work to
the DSP’s Safety Rules, unless otherwise agreed in writing.
A User may apply to the DSP for permission to work according to that
User’s own Safety Rules when working on its Plant on the DSP’s sites. If
the DSP is of the opinion that the User Safety Rules provide for a level of
safety commensurate with that of the DSP’s Safety Rules, it shall notify
the User, in writing, that the User may use its own Safety Rules.
The DSP entering and working on the DSP’s Plant on a User site may be
requested by the User to work to the User Safety Rules. Until receipt of
such notice, the DSP’s Safety Rules will apply. The DSP shall not be
obliged to accede to this request where in the DSP’s reasonable opinion
the User’s Safety Rules do not provide a level of safety commensurate
with the DSP’s Safety Rules.
The DSP may apply to a User for permission to work according to the
DSP’s Safety Rules when working on its Plant on that User’s sites. If the
User is of the opinion that the DSP’s Safety Rules provide for a level of
safety commensurate with that of that User’s Safety Rules, it shall notify
the DSP, in writing, that the DSP may use its own Safety Rules. Until
receipt of such notice, the DSP’s Safety Rules will apply.
Site Responsibility Schedule
A set of Connection site schedules shall be prepared identifying the
equipment and ownership at the Connection site, the Connection Points
and the responsibilities for safety, control and maintenance.to inform site
staff and DSP(s) of agreed responsibilities for Plant at the operational
interface.
Operation and gas (SF6) zone diagrams
Operating diagrams
An operating diagram shall be prepared for each Connection site at which
a Connection Point exists. The operating diagram shall include all Plant
and the Connections to all external circuits and incorporate numbering,
nomenclature and labelling as agreed with the DSP. At those Connection
sites where SF6 gas-insulated metal enclosed switchgear and/or other
SF6 gas-insulated Plant is installed, it must be depicted within a
delineated area which intersects SF6 gas-zone boundaries. The
nomenclature used shall conform to that used on the relevant Connection
site and circuit. The operating diagram (and the list of technical details) is
intended to provide an accurate record of the layout and circuit
interconnections, ratings and numbering and nomenclature of Plant and
related Plant.
Gas (SF6) zone diagrams
An SF6 Gas Zone Diagram shall be prepared for each Connection site at
which a Connection Point exists where SF6 gas-insulated switchgear
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Connection Conditions
and/or other SF6 gas-insulated Plant is utilised. The nomenclature used
shall conform to that used in the relevant Connection site and circuit. The
use of symbols shall conform to guidance set out by the DSP.
Site Common Drawings
Site Common Drawings shall be prepared for each Connection site and
shall include Connection site layout drawings and electrical layout
drawings and they will identify the responsibilities for common services
drawings. These items will form part of the Connection Agreement that
will also require common Protection/control drawings to be available to all
relevant parties.
Access
The provisions relating to access to the DSPs’ sites by Users, and to
Users’ sites by the DSPs (as required under GC.4), are set out in each
Connection Agreement between the DSP and each User. In addition to
those provisions, where a DSP, site contains exposed MV conductors,
unaccompanied access shall only be granted to individuals holding
appropriate authorisation.
Maintenance standards
It is a requirement that all Users’ Plant on the DSPs’ sites is maintained
adequately for the purpose for which it is intended and to ensure that it
does not pose a threat to the safety of any the DSPs’ Plant or personnel
on the DSPs’ sites.
DSPs shall have the right to inspect the test results and maintenance
records relating to such Plant at any time.
It is a requirement that all DSPs’ Plant on Users’ sites is maintained
adequately for the purposes for which it is intended and to ensure that it
does not pose a threat to the safety of any User Plant or personnel on the
User site. Users shall have the right to inspect the test results and
maintenance records relating to such Plant, at any time.
Site operational procedures
The DSP and Users with an interface with DSPs, must make available
staff to take necessary safety precautions and carry out operational duties
as may be required to enable work/testing to be carried out and for the
Plant Connected to the Distribution System.
Requirements for All Users
Import/export Capacity
A User shall not exceed the import/export capacities agreed in the
Connection Agreement unless specifically agreed with the DSP.
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Connection Conditions
Compliance
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 ESPM.
If an existing User does not comply with the technical and design
standards set down in CC.6, or cannot comply (for technical or economic
or other reasons) with the requirements of this section, the User shall seek
derogation from the provision from WERA.
Where a Generating Unit is to be installed and operated in parallel with
the Distribution System within an existing User’s installation, the DSP
shall be informed. The DSP has the right to inspect generating installations to
ensure that the requirements are met. In some cases, the DSP may require
a demonstration by Operation of the Generating Unit. Such
demonstrations shall be by agreement with the User.
DSP has the right to witness
The DSP has the right to witness aspects of the commissioning testing of
a Generating Unit and the Harmonic emissions testing or Flicker
compliance testing of any Plant. The DSP will signal its intention to
witness tests in a timely manner.
Power Factor
Each User with Demand shall maintain a Power Factor of not less than
0.85 lagging at the interface with the DSP. No User shall present a leading
Power Factor to the DSP system unless resulting from Operation of its
Generation as agreed or instructed by the DSP.
Change in Power Factor range
By 21.10.1438 H. Users must improve their Demand related Power
Factor to not less than 0.90 lagging and by 21.10.1443 H to a minimum of
0.95 lagging. The DSP may require proof that this has been achieved.
Users with both generation and Demand shall not transgress 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 Code.
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.
Phase Unbalance for Users with a Dedicated Transformer
Users with a dedicated transformer shall ensure that their loads are so
balanced that load unbalance which they create on the MV system meets
the User negative-phase-sequence current criteria of 1%.
Phase Unbalance for Users supplied at 13.8kV
Users supplied at 13.8kV or a higher Voltage shall balance their loads,
such that the load phase unbalance at the Customer User interface
meets the User negative-phase-sequence current criteria of 1%.
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Connection Conditions
Phase Unbalance for all Other Users
All other Users shall balance their loads over the three-phases to the
greatest degree possible. The DSP shall then balance these loads, within
the power system, to meet the above Voltage criterion.
Harmonics
Users with Generating Units or Demand must not generate Harmonic or
inter-harmonic currents at levels greater than are stated in SASO IEC
61000-3-6.
The planning levels for the Total Harmonic Distortion are up to
33kV = 6.5% and above 33kV = 3%
No direct current shall be injected into the grid.
Motors and Disturbing Loads
Users of the Distribution System must not generate Voltage
disturbances at a level that would affect other Users. In order to ensure
this, Users equipment must comply with SAOS IEC 61000-3-7.
Controllable Demand
Controllable Demand is Demand that may be controlled by the DSP or
another party acting as a service provider, licensed Retailer or Trader.
It is not the function of this Distribution Code to regulate the commercial
arrangements or agreements.
Users seeking to offer Controllable Demand as a service to the DSPs
should agree the format of signals to be used for load management. DSPs
should, to the extent possible, attempt to standardise such signals in line
with best practice.
The Controllable Demand must be compliant with the Distribution Code
requirements for Users with Demand.
Users with Demand and Generating Units
Users with both Demand and Generating Units shall comply with the
Distribution Code requirements for Generating Units based on the
Registered Capacity of that generation. Such Users are also required to
comply with the Distribution Code requirements relating to their load
equipment in order to manage the effects on the Distribution System and
other Users.
Vehicle Charging
Vehicle charging is treated as Demand (with maximum Demand managed
to a pre-defined limit set in the Connection Agreement) or as
Controllable Demand (CC.8.1.7). Where the vehicle charging is
configured to also re-supply energy to the Distribution System, the
device is treated as Energy Storage.
Energy Storage
At times, Energy Storage behaves as a Demand and at times behaves as
a Generating Unit. The DSP shall ensure that the transient Voltage
effects on the relevant part of Distribution System do not exceed
permitted limits when Energy is changed from maximum import to
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Connection Conditions
maximum export or maximum export to maximum import capacity or shall
limit the operational ramp rate of the Energy Storage as a condition of
Connection within the Connection Agreement.
Requirements for Power Producers
Layout of Requirements for Power Producers
CC.8.2 shall be complied with by all Power Producers falling within the
Scope CC.3 of these Connection Conditions.
In addition, Users with Generating Units shall comply with the schedules
appropriate to their Generating Units.
The Generating Unit Performance Schedules are as follows:
Schedule 1 Performance of all Synchronous Generating Units
Schedule 2 Performance of all Asynchronous Generating Units
Requirements for All Power Producers
Power Producers that have Generating Units subject to Central
Dispatch shall additionally have to comply with the SAGC) in respect of
those Generating Units.
For Generating Units not subject to Central Dispatch the electrical
parameters to be achieved at the Connection Point shall be specified by
the DSP within the Connection Agreement.
Any Generating Unit must be designed for normal Operation in the
presence of disturbances at the levels that can be expected, as indicated
in the above standards.
Standby generation
Generating Units that operate in stand-by mode are exempt from this
Distribution Code. By design, a standby generator will not to operate in
parallel with the Distribution System.
Tolerance of System Conditions
Voltage
Generating Units shall tolerate, without tripping, the system Voltage
conditions set down in PC.4.2.2. For Voltages above the highest Voltage
stated, or below the lowest Voltage stated, Generating Units may be
tripped to protect the Plant.
Frequency Response of Generating Units with a Registered Capacity of 2MW
or more
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.
There must be no reduction in Output from a Generating Unit within the
Frequency range 59.5 Hz to 60.5 Hz whilst Frequency is falling. Within
the Frequency range 59.5 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 Generating Units driven by Renewable Resources the
Output is dependent upon the availability of the Renewable Resource,
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Connection Conditions
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
Below 57.0Hz Power Producers may disconnect to protect their
Generating Units and associated equipment.
Rate of Change of Frequency
Generating Units must be capable of withstanding a 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.
Energization of Synchronous Generating Units
Unless proven facilities exist for the automatic resynchronisation of
Synchronous power generating modules with the rest of the Distribution
System then Power Producers shall ensure that their Synchronous
Generating Units are disconnected and, under the DSP’s instruction,
prepared for manual resynchronisation.
Synchronous Generating Units shall not be reconnected to the
Distribution System before the Total System Frequency is within the
range 58.8Hz – 60.05Hz and before the Voltage at the Connection Point
has remained within the range 95% - 105% of nominal for a minimum of
60 seconds.
Synchronisation of a Synchronous Generating Unit with the
Distribution System should not create a transient Voltage variation of
more than 4%.
Energisation / ramping of Asynchronous Generating Units
Following emergency or planned disconnection from the Distribution
System (other than as part of normal climatic Operation of a renewable
energy Asynchronous Generating Unit) an Asynchronous Generating
Unit with a Registered Capacity of 2MW or more, and which is not
Centrally Dispatchable, shall not re-connect to the Distribution System
without the prior permission of the DSP.
Asynchronous Generating Units shall not reconnect or increase Output
when the system Frequency is above 60.2Hz.
For Generating Units, 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.
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Disconnection during Islanding
It is conceivable that a part of the Distribution System, to which a
Generating Unit is Connected can become isolated from the Total
System.
A Power Producer’s Plant 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, induction
Generating Units or other Asynchronous Generating Units must trip
within 500ms of becoming islanded.
A Power Producer’s Plant can remain Connected and continuously
control Voltage and Frequency within the limits set down in this
Distribution Code only with prior agreement with the DSP.
The Power Producer shall not Synchronise and energise (in the case of
Asynchronous Generating Units) without first obtaining permission from
the DSP unless prior agreement has been reached with the DSP.
Automatic resynchronization as discussed in CC.8.2.3.4 is a prerequisite
for such an agreement in the case of Synchronous Generating Units.
A procedure shall be set out and agreed between the DSP and each Power
Producer for return to service. In the case of automatic resynchronization,
the procedure may include a standing Dispatch Instruction. In all other
cases, a specific Dispatch Instruction shall be issued by the DSP.
Generating Unit Performance – Active Power Control
In assessing the Active Power performance of Generating Units, due
regard shall be taken of the environmental conditions and the incident
energy to Power Output curve in the Connection Agreement.
Generating Units with Registered Capacity greater than 200kVA
Generating Units with Registered Capacity greater than 200kVA shall
ensure that such Generating Units are capable of Operation in
Frequency Sensitive Mode.
Active Power Output of each Generating Unit with a Registered Capacity up
to 2MW
The Active Power Output of each Generating Unit with a Registered
Capacity up to 2MW shall not vary more than proportionately with:
Voltages within the range stated in PC.4.2.2 indefinitely but
Voltages within the range ±10% of nominal Voltage for up to
30 minutes;
System Frequency within the range 57Hz to 60.5Hz.
The Active Power Output of each Generating Unit with a Registered Capacity
above 2MW
The Active Power Output of each Generating Unit with a Registered
Capacity above 2MW shall not be affected by:
Voltages within the range stated in PC.4.2.2 indefinitely but
Voltages within the range ±10% of nominal Voltage for up to;
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Connection Conditions
system Frequency within the range 59.5Hz to 60.5Hz.
The Active Power Output of each Generating Unit with a Registered
Capacity above 2MW shall not decrease by more than a proportionate
amount with Frequency within the range 59.5Hz to 57Hz provided that the
overall Frequency shift is not more than 4%/Hz.
Obligation to operate below maximum generation
There shall be no Distribution Code obligation placed upon such Power
Producers to normally operate below maximum generation Output
although such matters may be agreed in bi-literal agreements.
When in Frequency Sensitive Mode the following control facility shall be
operational with settings agreed with the DSP.
The Frequency Sensitive Mode Active Power fast acting controller shall
permit the setting of separate Deadbands and Droops for Frequencies
above and below 60Hz.
Deadband settings
Deadbands shall be settable with a lower limit between 59.0Hz and
60.0Hz in steps of 0.05Hz and an upper limit between 60.0Hz and 61.0Hz
in steps of 0.05Hz.
Active Power Droop settings
The Active Power Droop shall be adjustable within the range 2% and 8%
in 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
5%.
Active power regulation capability
With 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 59.8Hz or above 60.2Hz respectively. Figure
3 shows this graphically.
Output (MW)
Deadband
settable
Droop
settable
60
Frequency (Hz)
Figure 3: Graphic representation of the “Governor” function for both Synchronous Generating
Units and Asynchronous Generating Units
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Connection Conditions
For Frequencies above 61Hz, the controller shall detect the overFrequency and automatically switch to Frequency Sensitive Mode and
ramp-down Output according to a regime agreed with the DSP who shall
have regard to the TSP’s instructions.
For Frequencies below 59Hz, the controller shall detect the underFrequency and automatically switch to Frequency Sensitive Mode and
ramp-up any available Output according to a regime agreed with the DSP
who shall have regard to the TSP’s instructions.
Further Active Power performance requirements for Asynchronous
Generating Units are set down in Schedule 2.
Reactive Power Performance and Control
Generating Units with a Registered Capacity less than 2MW shall be
able to control the Power Factor to a value agreed with the DSP.
The Reactive Power capability must, as a minimum, lie within the range
0.95 absorbing to 0.95 generating as measured at the Connection Point
when the Generating Unit is operating at full Active Power Registered
Capacity.
Generating Units shall be equipped to vary their Reactive Power so as
to control Voltage local to the 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.
Generating Unit Operating on a Fixed Power Factor
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 GC.4).
The Reactive Power control requirements for Synchronous Generating
Units having a Registered Capacity greater than 2MW are set down in
the Performance Schedule 1 - Synchronous Generating Units.
Further Reactive Power control requirements for Asynchronous
Generating Units of all sizes are set down in the Performance Schedule 2
- Asynchronous Generating Units.
Low Voltage Ride Through
Low Voltage Fault Ride through capability of Generating Units of up to
200kW
Generating Units of up to 200kW Connected to the Distribution
System need not ride through faults.
Low Voltage Fault Ride through capability of Generating Units greater than
200kW and less than 2MW
Under transient conditions, Generating Units 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 300ms in any one phase or combination of
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Connection Conditions
phases, followed by a period of one second where Voltage may vary in
the range 80-110% of the nominal Voltage.
Low Voltage Fault Ride through capability of Generating Units greater than
2MW
Each Generating Unit with a Registered Capacity above 2MW is
required to remain Connected and stable for any balanced and
unbalanced fault where the Voltage at the Connection Point remains on
or above the heavy black line shown in Figure 4.
The Voltage against time curve applicable to Synchronous Generating
Units >2MW is shown in the solid line In Figure 4 and for Asynchronous
Generating Units > 2MW in the dashed line.
1.10
Connection point voltage (p.u.)
1.00
0.90
0.85
0.70
0.05
0.00
0.00
0.30
0.70
Time(s)
1.50
Figure 4: Fault ride through requirements for Synchronous and Asynchronous Generating Units
Short Circuit Contribution
The requirements for Synchronous Generating Units to limit fault infeed
are set down in the Performance Schedule 1 - Synchronous Generating
Units.
The requirements for Asynchronous Generating Units to make a short
circuit infeed contribution are set down in the Performance Schedule 2 –
Asynchronous Generating Units.
Black Start Capability
Obligations related to Black Start capability are set down in Performance
Schedule 1 - Synchronous Generating Units. Where Black Start is
available, and DSP(s) intend to rely upon that facility, DSP(s) may test /
witness test the facility as part of Commissioning Tests.
A User who has a Black Start agreement with the TSP shall declare this
to the DSP either as part of Connection Data or at a later date.
Performance Schedule 2 – Asynchronous Generating Units states that
there is no obligation on this type of Plant.
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Connection Conditions
Communication
Each Power Producer shall ensure that it complies, in respect of each
Generating Unit within its facility, with a list of signals as set by the DSP,
which details the destination, list and format of signals required to enable
information and normal and emergency control of the Generating Unit.
The DSP will have the right to test performance of these signals and the
DSP may withhold a Temporary Connection Certificate or Final
Connection Certificate or replace a Final Connection Certificate with a
Limited Performance Certificate until such time as the problem has
been rectified and the communication is proven to work.
Each party (TSP, DSP and SSECC) empowered to issue and receive
signals from Users is required to have proper regard for the security of the
Total System or Distribution System from cyber threats and all control
centres, the DSP 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 cyber-attack risks to any party.
Generating Plant Commissioning Tests and Compliance Certification
Where the Generating Unit requires Connection to the Distribution
System in advance of the commissioning date, for the purposes of testing,
the Power Producer shall comply with the requirements of the
Connection Agreement.
Provision of a commissioning Programme
The Power Producer shall provide the DSP with a commissioning
programme, for approval by the DSP prior to any testing.
The DSP shall approve the commissioning programme, if reasonable, to
allow Commissioning Tests to be co-ordinated.
The Power Producer shall, as a minimum, confirm that at least interface
Protection (as described in the Protection philosophy document
(CC.5.3)) and preferably the main Generating Unit Protection has been
proven to function as designed.
DSP Right to Witness Compliance Tests
Commissioning testing proves for the User that the Plant supplied and
installed is functioning as agreed. Tests may be required by the DSP to
prove Distribution Code compliance. The DSP has a right to witness
these compliance tests and will advise in a timely manner if it is the
intention to do so. The results of compliance tests shall be supplied to the
DSP in an agreed format.
Issuance of a Final Connection Certificate
On successful completion of compliance testing the DSP shall issue a
Final Connection Certificate. Where a test fails to meet the requirements
of the Distribution Code, the DSP may refuse Connection or may issue
a Temporary Connection Certificate valid for a time to allow the matter
to be rectified whilst the Generating Unit is permitted to be operational.
Alternatively, the DSP may issue a Limited Performance Certificate
restricting the Generating Unit in some way.
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Connection Conditions
If Plant later fails to meet Distribution Code requirements its Final
Connection Certificate may be withdrawn by the DSP and if appropriate
one of the other certificates issued or a Final Connection Certificate may
be issued for reduced capacity.
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Appendix D – Performance schedules
Schedule A
Reactive Power capacity and control
This section is to be read in conjunction with CC.6.2.6.
Generating Units having a Registered Capacity greater than 2MW
As stated in CC.8.2.8, each 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 0.95 Power
Factor (absorbing) and 0.95 Power Factor (generating) measured at the
Connection Point. This performance must be achievable when Voltage
is within the range stated in PC.4.2.2.
Each 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 AVR system targeted at
controlling the Synchronous Generating Unit terminal Voltage. The
AVR shall be designed and operated to maintain the steady-state terminal
Voltage within ± 0.5% of the set point in the normal Voltage range
specified in PC.4.2.2 without instability over the entire operating range of
the Synchronous Generating Unit. Power Producers shall not disable
this automatic Voltage control mode without prior approval of the DSP.
Each Synchronous Generating Unit with a Registered Capacity greater
than 2MW shall be equipped with VAr limiting equipment.
Short-Circuit Contribution
It is preferable that in the case of single-phase to Earth faults, the shortcircuit current contribution of a Synchronous Generating Unit shall not
exceed the short-circuit current in each phase occurring during a solid
three-phase fault. This is to ensure that equipment ratings are not
exceeded. In the event that calculation by a Power Producer 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.
For three-phase Synchronous Generating Units, the 1-phase shortcircuit current shall not be below 60% of the 3-phase short-circuit current
in order to facilitate Protection selectivity.
Black Start Capability
Power Producers with Synchronous Generating Units with a
Registered Capacity greater than 2MW shall notify DSP(s) if their
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Connection Conditions
generating Plant has a restart capability without Connection to an
external power supply.
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Connection Conditions
Schedule B
Active Power control
The Active Power Output of an Asynchronous Generating Unit with
Registered Capacity greater than 2MW shall be controllable as long as
technically feasible based on the available energy.
Each Asynchronous Generating Unit with a Registered Capacity
greater than 2MW shall be controllable remotely by the DSP, shall obey a
properly formatted Dispatch Instruction received from by 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.
Power Producers shall ensure that the following interface control and
performance requirements are met in respect of each of their
Asynchronous Generating Units:
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 which is a control system applied to a
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
Distribution System or the Total System.
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; there shall be three ramp rates as follows:
Emergency ramp rate is an automatic priority to ramp as fast as
possible when Frequency is outside normal operating limits.
automatic confirmation that:
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
energy and the power curve as specified/set out in the Connection
Agreement.
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Connection Conditions
Reactive Power capacity and controllability
Asynchronous Generating Units with Registered Capacity less than 2MW
Asynchronous Generating Units with Registered Capacity less than
2MW are of two types. Type A Generating Units are induction generators
without any form of electronic converter associated with either the rotor
current or the entire Output of the generator. These generators cannot
operate in the capacitive quadrant (supplying VArs) and the requirement
is that they operate between 0.98 and 0.95 Power Factor absorbing
Reactive Power (inductive quadrant). Type B Asynchronous
Generating Units are all other Asynchronous energy sources
Connected to the Distribution System. Type B Generating Units shall
comply with the following requirements:
For Asynchronous Generating Units with a Registered Capacity
less than 2MW, when the Active Power Output is below 20% of
Registered Capacity, the Asynchronous Generating Unit will
maintain its absolute Reactive Power below 4% of Registered
Capacity for nominal Voltage unless equipped to perform as an
Asynchronous Generating Unit of larger size.
Additionally, an Asynchronous Generating Unit with a Registered
Capacity greater than 200kW and less than 2MW will have the
capability to maintain its Power Factor at or below 0.95 lagging if the
Voltage at Connection Point is below 90% of nominal b and at or
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. Figure 5 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.
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P (p.u.)
Connection Conditions
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
-0.33
Consumption (lead) MVAr capability of power
production module at the connection point
Q
Pmax
0.33
Product ion (lag) MVAr capability of power
product ion module at the connection point
Voltage control mode / reactive power dispatch mode
Power factor control mode
Figure 5: Minimum Reactive Power requirements for Asynchronous Generating Units ≥2MW
depending upon the selected control mode
Asynchronous Generating Units having a Registered Capacity greater than
2MW
Asynchronous Generating Units with Registered Capacity of 2MW or
greater shall comply with the following requirements:
Required Reactive Power at full Output
Each Asynchronous Generating Units with Registered Capacity of
2MW or greater (when the Voltage is nominal), whether manufactured as
Type A or Type B (see CC.S2.2.1) 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. This requirement
applies when the level of Output is above 20% of Registered Capacity,
unless an alternative value of Active Power threshold is agreed upon by
the DSP in the Connection Agreement (as allowed for in GC.4).
The required Reactive Power performance is control mode dependent as
shown in Figure 5. Figure 5 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 6 (i.e. reactive power capability within the shaded
area).
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Connection Conditions
110%
Nominal voltage
105%
Reactive capability not
required in this area
100%
95%
90%
generating
0.33 p.u.
absorbing
0
0.33 p.u.
Figure 6: Per unit Reactive Power at the Connection Point based upon 1p.u. Active Power rating
Reactive Power limitation below 20% Output
For values of Active Power Output below 20% of Registered Capacity,
each Asynchronous Generating Unit 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 pu based on rated Power at
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.
Reactive Power following Faults
Asynchronous Generating Units 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 an Asynchronous Generating Unit is supporting the Distribution
System Voltage through Reactive Power export, it shall not draw
Reactive Power during or immediately following the disturbance.
Reactive Power control functions
Each Asynchronous Generating Unit 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 DSP(s). The initial control mode and settings
will be provided in the Connection Agreement. Each Asynchronous
Generating Unit shall be capable of the following control modes:
Voltage control mode;
Reactive Power control mode;
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Power Factor control mode;
Accuracy of control
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.
Managing overvoltage
In the event that Voltage exceeds the normal range specified in PC.4.2.2
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 PC.4.2.2. The control mode
requirement is shown graphically in Figure 7.
TRIP
Voltage (p.u.)
Must be in voltage control
Power factor / reactive power
voltage control
Must be in voltage control
TRIP
Figure 7: Deployment of modes of Reactive Power control for Asynchronous Generating Units
Extreme situations – obligation to trip
In the event that the above emergency action by the Generating Unit
cannot achieve a Voltage within a specified limited time, the Generating
Unit must trip as shown in Figure 7. It is possible to combine the Reactive
Power control action with an Active Power control action to maximise the
opportunity for the Asynchronous Generating Unit to remain
Connected. Such complex control actions are to be agreed with the DSP.
Return to service and normal control
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.
Short-Circuit Contribution
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
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Connection Conditions
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.
Black Start Capability
Asynchronous Generating Units 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.
Generating Plant Commissioning Tests
It may not be possible to fully prove compliance for some time after
energization, especially in the case of wind power Asynchronous
Generating Units. This particularly applies to proving compliance with the
Fault Ride Through characteristic. A temporary compliance certificate shall
be issued to the Power Producer in respect of an otherwise compliant
Asynchronous Generating Unit until a final compliance certificate can be
issued.
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OPERATING CODE
CONTENTS
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DEMAND FORECASTING
Introduction
In order for the DSP to operate the Distribution System efficiently and to
ensure maximum system security and system stability, there is a need for
those Users specified in OC.2.1 to provide loading and generation Output
information to the DSP.
Demand forecasting specifies the information to be provided to the DSP
by other Users of the Distribution System so that these requirements
can be met.
OBJECTIVE
This Operating Code sets out the Demand forecasting and the
Generating Unit Output information to be provided by Users to enable
the DSP to operate the Distribution System, and specifies the
information to be provided by Users to the DSP.
Generating Units incorporating Energy Storage behave, when importing
energy, as Demand, and when exporting energy, as Generating Units.
Power Producers should provide loading and generation Output
information as required by the DSP from other Users with Demand or
Generating Units.
Users with Controllable Demand should identify that part of their load
that is controllable.
The means of providing the information to the DSP and its confirmation
includes any non-transitory written form, or any other suitable means of
electronic transfer, which enables the recipient to retain information.
Scope
Demand forecasting applies to the following Users of the Distribution
System:
Major Customers Connected to the Distribution System and
Medium Voltage Customers where the DSP considers it
appropriate;
Power Producers with a Registered Capacity greater 2MW and
whose Generating Units are not subject to Central Dispatch;
Energy Storage with a Registered Capacity (in respect of
generating Output) greater than 2MW (or Demand greater than
1MW) and whose Energy Storage are not subject to Central
Dispatch; and
Energy Storage is greater than 2MW.
Information flow and coordination
DSPs shall co-ordinate Demand forecasting information for each Bulk
Supply Point to meet the requirement of the SAGC. DSPs 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 Bulk Supply Point.
Information from Power Producers for Generating Units greater than
2MW which are not subject to Central Dispatch, shall be provided to the
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DSP. Generating Units with a Registered Capacity greater than 200kW
may also be required to supply information at the discretion of the DSP.
Information regarding Renewable Resource Generating Units shall be
provided to DSPs (on request) through the SSECC.
Demand forecast data
Major Customers shall provide to the DSP information regarding
Demand and planned shutdowns for specified future periods. This shall
be provided on an annual basis when requested by the DSP. (Demand
forecast tables are to be found in PC Schedule D1 – User Demand
profiles).
Output Information
Generating Units with a Registered Capacity less than 200kW
The DSP will not require information from Power Producers with
renewable sourced Generating Units with a Registered Capacity less
than 200kW.
Generating Units with Registered Capacity of 200kW or greater
Information from Generating Units with Registered Capacity of 200kW
or greater is summarised in the Output schedules found in PC schedules
D3 and D4.
Generating Units with Registered Capacity greater than 200kW up to 2MW
Power Producers with Generating Units with a Registered Capacity up
to 2MW need not provide the DSP with information regarding Output 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. Generating
Units above 2MW
Generating Units with Registered Capacity above 2MW
Power Producers with Generating Units with a Registered Capacity
above 2MW not based upon Renewable Resource and not subject to
Central Dispatch shall provide the DSP with information regarding
Output for specified future periods. This shall be provided on an annual
basis according to a timetable set by the DSP.
Data for SSECC
Power Producers with Generating Units with a Registered Capacity
above 2MW based upon Renewable Resource and not subject to
Central Dispatch shall provide SSECC with information regarding Output
for specified future periods. This shall be provided on an annual basis
according to a timetable set by SSECC, which shall have regard to the
timetable set down by the TSP in the SAGC.
Data for TSP
Power Producers with 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 as required by the SAGC.
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OPERATIONAL PLANNING AND RETURN TO
SERVICE
Introduction
Operational Planning:
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 the DSP to operate the Distribution
System; and
specifies the information to be provided by Users to the DSP to allow
it to comply with its duties under the SAGC.
The means of providing the information to the DSP and its confirmation
includes any non-transitory written form, or any other suitable means of
electronic transfer, which enables the recipient to retain information.
In order for the DSP to fulfill the requirements of OC.3 it should be noted
that the information set out in the SAGC, to be provided by the TSP, will
form the basis of operational planning under OC.3.
Scope
OC.3 applies to the following Users of the Distribution System:
Major Customers Connected to the Distribution System where
the DSP considers it appropriate; and
Power Producers with Generating Units Connected to the
Distribution System.
Provision of Information
Information on Generating Units with a Registered Capacity greater
than 2MW and which are not subject to Central Dispatch (including
Power Producers with CHP and Customers with auto-production) shall
be provided, where specified, directly to the DSP.
Information on Renewable Resource Generating Units shall be
provided, where specified, to the DSP through the SSECC. Such
information relates to the Planned Outage of all or part of a Generating
Unit.
Centrally Dispatched Generating Units shall comply with the
requirements of the SAGC. Information shall be provided directly to the
TSP.
Information from Users with Controllable Demand of 2MW or more under
the control of the DSP shall be provided directly to the DSP.
Time scales and data
Detailed implementation of data gathering and timescales shall be
determined by the DSP and each User, except for Centrally Dispatched
Generating Units where the process will be set by the TSP. Due
recognition shall be given by the DSP to Voltage levels and capacities of
Plant and apparatus when assessing information requirements.
The information may be required for different timescales as may be
determined by the DSP’s planning needs.
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Information from Power Producers
Information supplied to the DSP from Power Producers with Generating
Units with a Registered Capacity 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. For the avoidance of doubt, the DSP will obtain such information
for Generating Units subject to Central Dispatch from the TSP.
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 Generating Units with a Registered Capacity
greater than 2MW, will be given to the DSP on annual basis through the
SSECC.
Information to Users
The DSP shall advise Major Customers, or Power Producers 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, or in the case of Centrally Dispatchable Plant from
the TSP, these shall be considered by the DSP and alternative
arrangements proposed if possible.
DEMAND CONTROL
Introduction
OC.4.1 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 could occur:1
2
3
4
In Normal conditions to optimize system operation or in case of
congestions
in the event of insufficient generating Plant and transfers from
external interconnections are not available to meet Demand;
to avoid disconnection of Customers; or
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.
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.
Means of reducing Demand
OC.4 deals with the following means of reducing Demand:
1
2
3
4
automatic low Frequency or Voltage Demand disconnection;
Customer Demand reduction including Voltage reduction;
Customer Demand management initiated by Licensed Suppliers or
other parties, other than following an instruction by DSP or the TSP;
Customer Demand reduction instructed by DSPs or the TSP; and
Emergency manual Demand disconnection.
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The term demand control is used to describe any or all of these methods
of achieving a Demand reduction.
Demand control Exercised by DSPs or the TSP
Where demand control is exercised by DSPs or the TSP it shall be done in
a manner that, in so far as reasonably practicable, does not discriminate
against any Customer or Licensed Supplier. DSPs or the TSP shall use
reasonable endeavours 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 criteria/plan submitted by the
DSPs and approved by WERA. DSPs shall consider the location of
significant local generation and arrange load shedding plans to maintain
that local generation, and any incidental load on that part of the
Distribution System.
Methods of Demand Control
Customer Demand may be disconnected automatically at selected
locations in accordance with the requirements of the SAGC and
arrangements agreed from time to time with the TSP, in the event of a
sudden fall in Frequency. Such arrangements shall be carefully
coordinated as part of an overall scheme and may take into account any
operational requirements or essential load.
Automatic Disconnection by Undervoltage Relays
Automatic disconnection by undervoltage relays 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.
Deliberate Reduction of Voltage
Deliberate reduction of Voltage may be used to achieve a temporary
reduction in Demand.
Deliberate Reduction in System Frequency
Deliberate reduction in system Frequency may also be used to achieve a
temporary reduction in Demand in accordance with the SAGC.
Emergency Manual Load Shedding
Emergency manual load shedding may be carried out on the Distribution
System or Transmission System for reasons of shortfall in supply or
other reasons.
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.
Implementation of Demand Control
Where demand control is exercised by the DSP in order to safeguard the
Distribution System the DSP shall liaise with and inform Users
accordingly, as far as is practicable.
Where demand control is exercised by a DSP on instruction or request
from the TSP in order to safeguard the Total System, then the DSP is
required to respond to the TSP requests promptly but shall liaise with and
inform other Users, so far as is practicable.
The procedures for load shedding including exemption policies, load
shedding rota and Customer communications are contained in the current
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version of the Distribution load shedding criteria/plan approved by
WERA.
Users may request information regarding their position on the load
shedding rota and to be updated as the rota itself is updated. WERA shall
also promptly receive a copy of the load shedding rota and any updates.
When preparing the load shedding rota, DSPs should have in mind not
only the history of load shedding, the criticality and characteristics of load
but also the balance of generation, and Demand in a zone and whether
any of the Demand is Controllable Demand.
The DSP shall complete the load shedding rota in Appendix H.
OPERATIONAL COMMUNICATIONS AND LIAISON
OC.5 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.
Scope
OC.5 applies to the following Users of the Distribution System:
1
2
Major Customers Connected to the Distribution System where
DSPs considers it appropriate; and
Generating Units with a capacity greater than 2MW, or according to
the Connection Agreement between a DSP and a Power
Producer.
Procedure
A DSP and each User Connected to the Distribution System shall
nominate persons and/or contact locations and agree communication
channels for the efficient exchange of information required by OC.5.
SCADA equipment may be required at a User’s site for transmission of
information and data to and from the DSP. The requirement to provide this
information shall normally be included in the relevant Connection
Agreement.
Information between a DSP and a User 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 System or User
Installation, in accordance with Good Industry Practice.
The DSP 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) which, in the opinion of the DSP, will have or may
have an Operational Effect on the installation of the User.
A User shall notify the DSP of any Operation on the installation of that
User which will have or may have an Operational Effect on the
Distribution System.
A notification under OC.5 shall include the name of the individual reporting
the Operation and, although it need not state the cause, shall be in
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sufficient detail to describe the Operation and to enable the recipient
reasonably to know and consider the implications and risks arising. The
recipient may ask questions to clarify the notification.
A notification under OC.5 shall be given as far in advance as possible, to
allow the recipient to consider and assess the implications and risks
arising.
Significant Incidents
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, the DSP, 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
OC.6.
Significant Incidents shall include Events, which result in, or may result
in, the following:
1
2
3
Voltage outside statutory limits;
System Frequency outside statutory limits; or
System stability failure.
EVENT REPORTING
Introduction
OC.6 sets the requirements for reporting in writing those Events deemed
to be Significant Incidents under OC.5.3.
OC.6 also provides for the joint investigation of Significant Incidents by
the Users.
Scope
OC.6 applies to the following Users of the Distribution System:
1
2
Major Customers Connected to the Distribution System where
the DSP considers it appropriate;
Power Producers having Plant with a Registered Capacity greater
than 2MW, or according to the Connection Agreement between the
DSP and User.
Procedures
A DSP and each User specified in OC.6.2 shall nominate officers and
establish communication channels to ensure the effectiveness of OC.6.
Such officers and communication channels may be the same as those
established under OC.5.
Communication shall, as far as possible, be direct between the User and
the DSP. This does not, however, preclude communication with the
User’s nominated representative.
In the case of an Event that has been reported to the DSP under OC.5
and subsequently has been determined by the DSP to be a Significant
Incident, a written report shall be given to the DSP by the User in
accordance with OC.6.
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In the case of an Event that has been reported to the User under OC.5
and subsequently has been determined by the DSP to be a Significant
Incident, a written report shall be given to the User by the DSP in
accordance with OC.6.
The report shall be in writing or in electronic form and shall be sent to the
DSP or User, as the case may be. It shall contain confirmation of the
notification given under OC.5 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 OC.6.
A report under OC.6 shall be given as soon as reasonably practical after
the notification under OC.5.
Joint Investigations
Where a Significant Incident has been declared and a report submitted
under OC.6 either party or parties may request in writing that a joint
investigation be carried out.
The composition of such an investigation panel shall be appropriate to the
incident to be investigated and agreed by all parties involved.
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.
Matters to be Included in a Written Report of a Significant
Incident
Matters to be Included by all Participants
Matters applicable to DSPs and Power Producers or Major Customers
are as follows:
1
date and time of Significant Incident;
2
location;
3
equipment involved;
4
brief description of Significant Incident;
5
details of any demand control undertaken;
6
conclusions and recommendations, if applicable
Matters applicable to the DSP
Matters applicable to the DSP are as follows:1
Effect on Users and where appropriate:
2
Duration of incident; and
3
Estimated date and time of return to normal service.
Matters applicable to Power Producers and Major Customers
Matters applicable to Power Producers and Major Customers are as
follows:
1
2
3
4
date and time of Significant Incident;
location;
equipment involved;
brief description of Significant Incident;
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5
6
details of any demand control undertaken;
conclusions and recommendations if applicable.
SYSTEM TESTS
Introduction
OC6 sets out the responsibilities and procedures for arranging and
carrying out System Tests, which have or may have an effect on the
systems of DSPs or Users. System Tests are either those which involve
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 Tests or re-Commissioning Tests
or any other tests of a minor nature.
Scope
OC.7 applies to the following Users of the Distribution System:
1
2
Major Customers Connected to the Distribution System where
the DSP considers it appropriate;
Power Producers with Plant having a Registered Capacity greater
than 2MW, or according to the Connection Agreement between the
DSP and the User.
Procedures
If the System Test is proposed by the DSP or the User Connected to the
Distribution System then the provisions of OC.7 shall apply.
All System Test procedures shall comply with all applicable legislation.
Tests subject to OC6
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.
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
Planning Code.
Period of notice of Test
When a DSP 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 the DSP, shall be given by the person
proposing the System Test (Test Proposer) to the DSP and to those
Users who may be affected by such a System Test.
Written Test Proposal Notice
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.
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. The DSP shall not be required to do anything under OC.7 until it
is satisfied with the details supplied in the proposal or pursuant to a
request for further information.
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Duties of DSP(s)
If a DSP wishes to undertake a System Test, the DSP shall be deemed to
have received a proposal for that System Test.
The DSP shall have responsibility for overall co-ordination of the System
Test, and, using the information supplied to it under OC.7, shall identify in
its reasonable estimation, which Users other than the Test Proposer, may
be affected by the proposed System Test.
Following receipt of the System Test proposal, the DSP shall evaluate the
impact of the System Test and discuss the proposals with Users
identified as being affected.
1
2
3
Within one month of receiving the System Test proposal the DSP
shall submit a report to the Test Proposer which shall contain
proposals for carrying out the System Test (including the manner in
which it is to be monitored);
an allocation of costs between the affected parties, (the general
principle being that the Test Proposer will bear the costs); and
such other matters that the DSP considers appropriate; an outline of
the procedure to be followed and the proposed test schedule and
advice regarding any costs.
The proposal report shall be submitted to all those who received a notice
under OC.7.3.3.
If the proposal report (or a revised proposal report as agreed between the
DSP and the Test Proposer) is approved by all recipients, the System
Test can proceed.
Test Programme
At least one month prior to the date of the proposed System Test, the
DSP shall submit to all recipients of the proposal notice
1
2
3
a programme which in OC.7 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 the DSP deems appropriate.
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.
Final report
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 the DSP.
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.
Results of tests shall be reported to relevant parties, taking into account
confidentiality issues.
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MONITORING TESTING AND INVESTIGATION
Introduction
In order to discharge its responsibilities in respect of safe, reliable and
economic Operation of the Distribution System and in accordance with
its Licence conditions the DSP shall organize and carry out monitoring,
testing and investigation on the effect of Users’ electrical apparatus or
electrical installation on the Distribution System.
Scope
OC.8 applies to the following Users of the Distribution System:
1
2
all Power Producers; and
all Customers who are Connected to the Distribution System.
Procedures
Testing
The DSP shall, from time to time, determine the need to test or monitor
the quality of supply at various points on the Distribution System.
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.
Where testing or monitoring is required at the Connection Point with a
User, then the DSP shall advise the User involved and the DSP shall
make available the results of such tests to the User.
Consequences of Tests
Where a User is found to be operating outside the technical limits
specified in the Distribution Code then the User immediately, or within
such time as agreed with the DSP, shall rectify the situation or disconnect
the apparatus which has been causing the problem from its electrical
system (Connected to the Distribution System).
Continued failure to rectify the situation shall result in the User being
disconnected.
Monitoring
The DSP shall, from time to time, monitor the effects of Users on the
Distribution System.
The monitoring shall normally be related to the amount of Active Power
and Reactive Power or Flicker or Harmonics transferred across the
Connection Point.
Consequences of Monitoring
Where the User is exporting or importing Active Power or Reactive
Power in an amount causing disturbances, the DSP shall inform the User
and the User shall restrict the power transfer to within the specified
parameters.
A User may request the DSP to demonstrate through monitoring or testing
that the quality of supply on the Distribution System meets the standards
stated in the PC in the absence of the User’s disturbing equipment.
A DSP may check from time to time that Users are in compliance with
agreed Protection requirements and Protection settings.
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SAFETY COORDINATION
Introduction
OC8 specifies the Safety Rules and procedures to be applied by the DSP
to meet statutory requirements and Distribution Licence conditions and
obligations.
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, otherwise reliance is to be placed on
working to the DSP’s Safety Rules.
Objectives
The objectives of Safety Coordination procedures are to:
lay down the Safety Management criteria to be applied,
to ensure safety of persons across operational and Ownership
Boundaries.
Scope
OC.9 specifies the Safety Rules and procedures that apply to the DSPs
and the following Users of the Distribution System:
1
2
3
4
all Power Producers;
Major Customers;
any other party reasonably specified by the DSP including Users
Connected at Medium Voltage or Low Voltage for appropriate
sections of OC.9 when necessary;
agents of the DSPs or Users working on the Distribution System or
at or across operational boundaries.
Procedures
The Safety Management principles and procedures (Safety
Management system) for ensuring the health and safety of all relevant
personnel shall be specified by the DSP and Users for work on their
respective systems or Plant and apparatus Connected to them.
There shall be joint agreement by DSPs and Users on which Safety
Management system is to be used for sites or locations where an
operational boundary exists and proper documentation of the safety
precautions to be taken shall be maintained.
There shall be written authorization of personnel who carry out the duties
of control, Operation, work or testing of Plant apparatus forming part of,
or Connected to, the Distribution System.
There shall be joint agreement between the DSP and each User as to
which of them specifies responsibility for system or control equipment and
which agreement shall ensure that only one party is responsible for any
item of Plant or apparatus at any one time.
The DSP and each User shall at all times have nominated a person or
persons responsible for the co-ordination of safety on the respective
system.
The DSP and each User shall maintain a suitable system of
documentation which records all relevant operational Events that have
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taken place on the Distribution System or other system Connected to it
and the co-ordination of relevant Safety precautions for work.
System diagrams which show sufficient information for control personnel
to carry out their duties shall be shall be maintained as current and shall
be exchanged between the DSP and User as required.
Site Responsibility Schedules as required in the CC.5.3 shall be kept
current and used to determine responsibilities for Operation, maintenance
and safety.
Safety at the DSP / User Interface
The following procedures set down the basic safety requirements at all the
User and DSP 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).
The DSP and the User shall be governed by OC.9.1 in deciding
whether the DSP’s Safety Rules or the User’s Safety Rules shall be
applied to any work activity. When work on equipment or when MV
Isolation is required or in other Complex electrical environments the
DSP and the User shall adopt a common form of record of:
Appendix E to this OC.9 sets out the form of record to be used,
although the record shall be in language understood by all parties.
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.
Electrical equipment Connected to either side of the interface and
interface equipment shall be under the control of a named person at
either side.
Each item of equipment shall be controlled by only one identifiable
person at any one time.
Adequate means of Isolation shall be provided at the interface to
allow work to be carried out safely at either side of the interface.
Where necessary to prevent danger adequate facilities for safety
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.
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.
All electrical equipment shall be suitably identified where necessary
to prevent danger.
Electrical installations and equipment shall comply with the relevant
statutory requirements.
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General matters for ensuring safety
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.
Instructions for operating and/or Earthing the User’s electrical equipment
shall be clearly displayed at the User’s switching location.
Safety procedures for personnel working on or in close proximity to the
Distribution System Plant and apparatus shall be governed by the DSP.
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.
DISPATCH CODE
Introduction
This OC.10 sets out the minimum requirements for Users whose
generation or Demand may be dispatched in part or in total by the DSP
and allows the DSP to test the availability of controllable Plant.
Scope
OC.10 specifies the arrangements and procedures that apply to DSPs and
the following Users of the Distribution System:
all Power Producers whose Generating Units are subject to
Dispatch by the DSP but not subject to Central Dispatch by the
TSP;
Users with Controllable Demand part or all of which may be
dispatched by the DSP but is not subject to Central Dispatch by the
TSP.
Content of Dispatch Instructions
Dispatch Instructions are instructions issued by the DSP to a User to
alter the operational state or mode of Operation of Plant, to Synchronise
or de-synchronise a Synchronous Generating Unit, to Connect or
disconnect an Asynchronous Generating Unit, to modify the amount of
Active Power (MW) or Reactive Power (MVAr) generated or consumed
at the User’s facility or to provide or change any other contracted system
service.
Arrangements for Information and Control
Control information is not required from Generating Units with a
Registered Capacity of less than 200kW, but may be provided.
Generating Units and Controllable Demand may or may not be subject
to Dispatch Instructions and may fall under separate bi-lateral
agreements falling outside the Distribution Code.In the case of all Plant
falling within the Scope of this OC.10 :
Either:
A Power Producer or User with Controllable Demand subject to
control by the DSP shall ensure that their Plant is equipped to
receive and transmit signals in a format and to the extent specified
by the DSP, including the operational state of the Plant and, where
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appropriate to indicate that the DSP’s signals have been received
and the signaled action has been completed or otherwise; or
Where acceptable to the DSP, Dispatch Instructions may be issued
and confirmed by telephone or other means of communication
provided that both the DSP and the User record the instructions and
confirmation of action.
A Dispatch Instruction, whether issued by method 1. or 2. above, to a
Renewable Resource Power Producer in respect of Generating Units
with a Registered Capacity greater than 2MW will be given by the TSP
through the SSECC.
Availability
Each Power Producer with Dispatchable Generating Units and each
User with Controllable Demand shall declare, in a format set down by
DSP, the amount of the generating Plant or load change which will be
available in each half-hour of each day for the week ahead, and again for
the day ahead. This is in addition to planning information required in
Schedules D3 and D4 to the PC.
Declaration of Availability for the Week Ahead
Declarations for the week ahead shall be made according to the following
times:
Sunday 11.00am and again on Thursday by 11.00
Declaration of Availability for the Day Ahead
Declarations shall be made for day ahead by 09.00 on the previous day
except that Power Producers and Users with Controllable Demand
should declare availability for any Friday and Saturday on Thursday by
09.00.
In the event that a Power Producer or User with Controllable Demand
becomes aware of circumstances which will change, or are likely to
change, to the previously declared weekly or daily advised availability, the
User must immediately inform the DSP that the availability has been, or
will, or may be changed.
Proving Availability
The DSP may at any time (but not more frequently than 6 times in a
calendar year except as provided for below) require the User to prove that
its Plant is available to produce Output to the extent declared by the
User, by instructing the Plant to meet the most recently declared
availability levels. Whether the Plant meets or fails to meet the declared
availability levels must be recorded by the DSP and advised to the User.
The DSP will then record the level achieved by the Plant as the maximum
availability until the User provides evidence that any problem has been
rectified.
In assessing the number of times when availability testing may be carried
out, any test where the availability fell below that declared by the User,
and any subsequently required test to prove that availability is restored
shall be disregarded.
In assessing availability of Renewable Resourced Generating Units, the
DSP should have due regard to the availability of the Renewable
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Resource (and the Power Curve in the User’s Connection Agreement)
at the time of the test.
The costs of availability testing are not the subject of the Distribution
Code and should be covered under separate agreements.
Energy Storage
Users with Energy Storage subject to Dispatch shall make available to
the DSP the following instantaneous (or averaged over a short time period
agreed with the DSP) information:
the mode of Operation of the Plant (Demand or generation);
the state of charge of the Plant and maximum charge/discharge rate
or pattern achievable at this time.
The measurements/information shall be time stamped.
Renewable Energy Generation Real Time Parameters
Power Producers with renewable energy generation shall make available
to the SSECC instantaneous or measurements on an agreed averaging
basis of appropriate renewable energy parameters:
Wind speed and direction;
Incident solar irradiation.
The measurements shall be time stamped.
Capability of receiving Dispatch Instructions
A non-Renewable Resource Power Producer with a Generating Unit or
Controllable Demand may or may not be subject to Dispatch
Instructions and this is a matter for bi-lateral agreements. If subject to
Dispatch Instructions, this will be as a contracted system service and is
therefore outside the Distribution Code.
Energizing and re-energizing Generating Units
The Power Producer shall not synchronize or reconnect and energise (in
the case of Asynchronous Generating Units) without first obtaining
permission from the DSP unless prior agreement has been reached with
the DSP. A Dispatch Instruction from the DSP is deemed to be such
agreement.
Automatic resynchronization as discussed in CC.8.2.3.4 is a prerequisite
for such an agreement in the case of Synchronous Generating Units.
A procedure shall be set out and agreed between the DSP and the Power
Producer for return to service.
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Appendix E – RISSP
Recording of Safety Precautions
Agreement of Safety Precautions
When a User or DSP wishes to carry out work and/or testing on or near its
system and it is of the opinion that, for this to be done safely, safety
precautions are required on the other’s system the following process shall
be undertaken:
1
2
in the case of work on a DSP’s apparatus, the DSP’s Requesting
Safety Coordinator will contact the User’s Implementing Safety
Coordinator; or
in the case of work on the User’s MV apparatus the User’s
Requesting Safety Coordinator will contact the DSP’s Implementing
Safety Coordinator;
In either case for the part of the system on which (or relating to which) the
safety precautions are required. This contact is made to agree, in
accordance with the procedure contained in this Appendix, the location at
which the safety precautions will be implemented or applied.
When a DSP wishes to carry out work and/or testing on or near the
Distribution System and it is of the opinion that, for this to be done
safely, safety precautions are required on (or relating to) more than one
User system the provisions of this Appendix shall be followed with regard
to each User separately.
Agreement of Isolation
The Requesting Safety Coordinator shall inform the Implementing Safety
Coordinator of the MV apparatus on which Safety from the system is to
be achieved and they will need to reach agreement on the location(s) at
which Isolation is to be established on (or relating to) the Implementing
Safety Coordinator's System.
The Implementing Safety Coordinator shall then promptly inform the
Requesting Safety Coordinator of the following:
1
2
3
for each location, the identity (by means of name and numbering or
position, as applicable) of each point of Isolation;
whether Isolation is to be achieved by an Isolating Device in the
isolating position or by an adequate physical separation or sufficient
gap or by disablement (by means of switching or dismantling) of
Plant and/or apparatus so that electrical energy cannot pass from
the apparatus (or, in the case of Plant, from the associated
apparatus) to the MV apparatus, other than by an Isolating Device;
and
the procedures to be taken under Safety Rules being applied to
clearly identify the isolated equipment and points of Isolation and to
ensure that no inadvertent re-energization can take place.
The Implementing Safety Coordinator shall maintain each point of
Isolation in accordance with the relevant Local Safety Instructions until
the Requesting Safety Coordinator confirms that Isolation is no longer
required and that it is safe (including any arrangements for Earthing
implemented by the Requesting Safety Coordinator) to re-energise the
previously Isolated part of the system.
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Agreement of Earthing
If, in addition to the Isolation requested under this Appendix E to OC.9 the
Requesting Safety Coordinator requires Earthing, he shall notify this
requirement to the Implementing Safety Coordinator and they will need
to reach agreement on the location(s) at which Earthing is to be
established on the Implementing Safety Coordinator's system until the
Requesting Safety Coordinator confirms that the arrangements for
Earthing are no longer required.
The Implementing Safety Coordinator shall then promptly inform the
Requesting Safety Coordinator for each location, the identity (by means
of apparatus name and numbering or position, as is applicable) of each
point of Earthing.
The Implementing Safety Coordinator shall maintain each point of
Earthing in accordance with the relevant Local Safety Instructions.
In the event of Disagreement
In any case where the Requesting Safety Coordinator and the
Implementing Safety Coordinator are unable to agree the location of the
Isolation and (if requested) Earthing, it shall be at the closest available
points on the in-feeds to the apparatus on which safety from the system is
to be achieved. The closest point will be as indicated on the Ownership
Boundary Diagram or, in the case where, by reason of the design of any
MV apparatus on which safety precautions are to be applied, it is not
practicable to apply safety precautions on that apparatus, it shall be at the
most appropriate point(s) on the User’s Plant and/or apparatus to achieve
safety from the system, as determined by the DSP.
Implementation of Isolation and Earthing
Once the location of Isolation and (if requested) Earthing are agreed, the
following procedure will apply:
1
2
the Implementing Safety Coordinator will ensure the implementation
of the Isolation;
the Implementing Safety Coordinator will confirm to the Requesting
Safety Coordinator that the Isolation has been established on their
system;
Work
Following confirmation by the Implementing Safety Coordinator to the
Requesting Safety Coordinator that all of the agreed safety precautions
have been established on or relating to the System of the Implementing
Safety Coordinator, the Implementing Safety Coordinator will record in
Section 1.1. of his RISSP-B the details of the MV apparatus on which he
has been told that safety from the system is required. The Implementing
Safety Coordinator will also record the safety precautions established on
or relating to the system of the Implementing Safety Coordinator onto
parts 1.1 and 1.2 of his RISSP-B.
Where Earthing was not requested (either because Earthing was
possible but was not required or because Earthing was not possible), part
1.2(b) of the RISSP-B will be completed with the words "not earthed".
The Implementing Safety Coordinator shall then contact the Requesting
Safety Coordinator and confirm, by reading out the details entered on
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parts 1.1 and 1.2 of RISSP-B, to the Requesting Safety Coordinator, that
the safety precautions have been established.
The Requesting Safety Coordinator will then complete parts 1.1 and 1.2
of RISSP-A with the precise details received from the Implementing
Safety Coordinator and then read back all those details to the
Implementing Safety Coordinator. If both confirm that the details entered
are the same, the Requesting Safety Coordinator shall issue the RISSP
identifying number, as stated on the RISSP-A, to the Implementing Safety
Coordinator who shall ensure that the number, including its prefix and
suffix, is correctly entered on the RISSP-B.
The Requesting Safety Coordinator and the Implementing Safety
Coordinator shall then respectively complete part 1.3 of RISSP-A and
RISSP-B (which relates to the identity and location of the Implementing
Safety Coordinator and the Requesting Safety Coordinator
respectively). Each Safety Coordinator shall then complete the issue of
the RISSP by signing part 1.3 of their respective RISSPs and then enter
the time and date. Once signed, no alteration to the RISSP is permitted;
the RISSP may only be cancelled. If a change is required then the original
RISSP shall be cancelled and a new RISSP shall be issued following the
above RISSP procedure so that the new RISSP incorporates the required
alterations. For the avoidance of doubt, if the need for an alteration to a
RISSP is discovered after the commencement of work or testing,
procedures in Safety Rules shall immediately be implemented to remove
all persons from danger and secure the zone until the procedure under a
new RISSP has been completed.
The signed copy of the RISSP shall be transmitted in facsimile form by an
agreed method by both the Requesting Safety Coordinator and the
Implementing Safety Coordinator for confirmation.
The Requesting Safety Coordinator is then free to authorise work, but
not testing. Where testing is to be carried out, the testing procedure set
out below shall be implemented. The procedure for carrying out the work
is entirely an internal matter for the party which the Requesting Safety
Coordinator is representing.
Testing
Where the Requesting Safety Coordinator wishes to authorise the
carrying out of a test to which the procedures in this Appendix E to OC8
apply he may not do so and the test will not take place unless and until the
following procedures have been followed:
1
2
confirmation is obtained from the Implementing Safety Coordinator
that no person is working on, or testing, or has been authorized to
work on, or test, any parts of the Systems within the points of
Isolation identified on the RISSP form relating to the test which is
proposed to be undertaken (the "original RISSP"), and the points of
Isolation on the Requesting Safety Coordinator’s System, and will
not be so authorized until the proposed test has been completed (or
cancelled) and the Requesting Safety Coordinator has notified the
Implementing Safety Coordinator of its completion (or cancellation)
and thereby the cancellation of the requirements;
all current RISSPs (except for the original RISSP under which
Testing is to be carried out) between the Requesting Safety
Coordinator and the Implementing Safety Coordinator which relate
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3
to those parts of the systems between the points of Isolation
identified on the original RISSP (under which Testing is to be carried
out) and the points of Isolation under these RISSPs on the
Requesting Safety Coordinator’s system), have been cancelled. ;
and
the Implementing Safety Coordinator agrees with the Requesting
Safety Coordinator to permit the testing on those parts of the
Systems between the points of Isolation identified in the original
RISSP and the points of Isolation on the Requesting Safety
Coordinator's System.
The Requesting Safety Coordinator will inform the Implementing Safety
Coordinator as soon as the test has been completed or cancelled. Where
Earthing has been removed during a test and has not been restored at
the original position upon completion or cancellation of the test, the
original RISSP shall be cancelled.
Cancellation
When the Requesting Safety Coordinator decides (having followed all
relevant internal procedures) that safety precautions are no longer
required, he will contact the Implementing Safety Coordinator and inform
him of the RISSP identifying number (including the prefix and suffix). The
Requesting Safety Coordinator shall read out to the Implementing Safety
Coordinator the details entered on parts 1.1 and 1.2 of his RISSP-A, and
the Implementing Safety Coordinator shall confirm that the details
entered on parts 1.1 and 1.2 of the RISSP-B are the same. The
Requesting Safety Coordinator shall then confirm to the Implementing
Safety Coordinator that the safety precautions are no longer required.
The Requesting Safety Coordinator and the Implementing Safety
Coordinator shall then respectively complete part 2.1 of RISSP-A and
RISSP-B (which relates to the identity and location of the Implementing
Safety Coordinator and the Requesting Safety Coordinator
respectively). Each Safety Coordinator shall then complete the
cancellation of the RISSP procedure by signing part 2.1 of their respective
RISSPs and then entering the time and date.
The Implementing Safety Coordinator is then free to arrange the removal
of the safety precautions, the procedure to achieve that being entirely an
internal matter for the party which the Implementing Safety Coordinator
is representing. The only situation in which any safety precautions may be
removed without first cancelling the RISSP is when Earthing is removed
for the purpose of testing.
The RISSP having been cancelled, all the co-ordination and information
exchange is required during the removal of earths and switching
processes shall be carried out using a telecommunication system
preferably having voice recording facility.
Where Earthing has been requested neither Safety Coordinator shall
instruct the removal of any Isolation forming part of the safety precautions
until it is confirmed to each by the other that all Earthing has been
removed. This must be confirmed using a telecommunication system
preferably having voice recording facility.
Loss of Integrity of Safety Precautions
In any instance when any safety precautions may be ineffective for any
reason the relevant Safety Coordinator shall without delay inform the
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other Safety Coordinator(s) of that being the case and, if requested, of
the reasons why. The work must be stopped and procedures in the Safety
Rules shall immediately be implemented to remove all persons from
danger and secure the zone until the conditions have been re-accessed
and restored to the original level.
Safety Log
The DSP and each User shall maintain a safety log which shall be a
chronological record of all messages relating to Safety Coordination
under OC.9 sent and received by the Safety Coordinator(s). The safety
log must be retained for a period of not less than 3 years.
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Appendix F – RISSP - A
[CONTROL CENTRE/SITE] RECORD OF INTERSYSTEM SAFETY PRECAUTIONS (RISSP-A)]
(To be completed by the Requesting Safety Coordinator)
RISSP Number
PART 1
1.1 MV APPARATUS IDENTIFICATION
safety precautions have been established by the Implementing Safety
Coordinator to achieve (in so far as it is possible from that side of the
Connection Point) safety from the system on the following MV apparatus
on the Requesting Safety Coordinator's system: [state identity name(s) and, where applicable, identification of the MV circuit(s) up to
the Connection Point]:
1.2 SAFETY PRECAUTIONS ESTABLISHED
ISOLATION
[State the location(s) at which Isolation has been established. For each
location, identify each point of Isolation. For each point of Isolation, state
the means by which the Isolation has been achieved and whether
immobilised and locked, safety notice affixed or other safety procedures
applied, as appropriate.]
EARTHING
[State the location(s) at which Earthing has been established. For each
location, identify each point of Earthing. For each point of Earthing, state
the means by which the Earthing has been achieved and whether
immobilised and locked or other safety procedures applied, as
appropriate].
1.3 ISSUE
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I have received confirmation from ________________ (name of
Implementing Safety Coordinator) at __________________ (location)
that the safety precautions identified in paragraph 1.2 have been
established and that instructions will not be issued at his location for their
removal until this RISSP is cancelled.
Signed __________________ (Requesting Safety Coordinator)
at ____________________ (time) on ___________________ (date)
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PART 2
2.1 CANCELLATION
I have confirmed to _______________________ (name of the
Implementing Safety Coordinator) at _____________________
(location) that the safety precautions set out in paragraph 1.2 are no
longer required and accordingly the RISSP is cancelled.
Signed _____________________ (Requesting Safety Coordinator)
at ________________________ (time) on ____________________
(Date)
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Appendix G – RISSP - B
[CONTROL CENTRE/SITE] RECORD OF INTERSYSTEM SAFETY PRECAUTIONS (RISSP-B)]
(To be completed by the Implementing Safety Coordinator)
RISSP Number
PART 1
1.1 APPARATUS IDENTIFICATION
Safety precautions have been established by the Implementing Safety
Coordinator to achieve (in so far as it is possible from that side of the
Connection Point) safety from the system on the following apparatus on
the Requesting Safety Coordinator’s system: [state identity - name(s)
and, where applicable, identification of the circuit(s) up to the Connection
Point]:
1.2 SAFETY PRECAUTIONS ESTABLISHED
ISOLATION
[State the location(s) at which Isolation has been established. For each
location, identify each point of Isolation. For each point of Isolation,
state the means by which the Isolation has been achieved and whether
immobilised and locked, safety notice affixed or other safety procedures
applied, as appropriate.]
EARTHING
[State the location(s) at which Earthing has been established. For each
location, identify each point of Earthing. For each point of Earthing,
state the means by which the Earthing has been achieved and whether
immobilised and Locked or other safety procedures applied, as
appropriate].
1.3 ISSUE
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I have confirmed to (name of Requesting Safety Coordinator) at
________________________ (location) that the safety precautions
identified in paragraph 1.2 have been established and that instructions will
not be issued at my location for their removal until this RISSP is cancelled.
Signed ______________________ (Implementing Safety Coordinator)
at ______________________ (time) on _____________________ (date)
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PART 2
2.1 CANCELLATION
I have received confirmation from __________________ (name of the
Requesting Safety Coordinator) at _________________ (location) that
the safety precautions set out in paragraph 1.2 are no longer required and
accordingly the RISSP is cancelled.
Signed _____________________. (Implementing Safety Coordinator)
at ______________________. (time) on ________________________.
(Date)
(Note: This form to be a different colour from RISSPA)
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Appendix H – Load shedding tables
Load Shedding Block X
Feeder Name
Location
Max Demand
Feeder 1
Feeder 2
Feeder 3
Feeder …
Feeder n
Table for Excluded Circuits
Customer
Feeder
Max Demand
Extra column to be added
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Explanation
Metering Code
METERING CODE
CONTENTS
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MC.1
INTRODUCTION
In order to account for the flow of electricity through the Distribution
System, it is imperative that suitable and accurate metering and recording
facilities are provided at all Connection Points to the Distribution
System. This chapter deals with Metering and recording requirements for
Users and clarifies the obligations Users relating to such installations. It
also sets the minimum technical, design and operational criteria to be
complied with relating to Metering, installations and data collection
equipment.
The provisions of this chapter are specifically applicable to issues relating
to the following:
1
2
3
MC.2
supply, installation maintenance, testing and verification of Meters;
collection, storage and communication of metering data; and
competencies and standard of performance of participants relating to
metering.
OBJECTIVE
The objective of this Metering Code is to set out the responsibilities
relating to the measuring and recording of Active Power and Reactive
Power, Apparent Energy , Power Factor for both Import and Export
parameters, Energy Imports to, or Energy Exports from the Distribution
System. This Metering Code also specifies the conditions that will govern
the Meters and recording equipment and systems employed.
MC.3
SCOPE
Application of the Metering Code
The Metering Code applies:
to licensed DSPs;
to Users Connected to the Distribution System at MV or LV where
the installed Meter is used for revenue and billing purposes.
This Metering Code applies to all Users with a Connection Point to the
Distribution System.
When the Metering Code does not apply
This Metering Code does not apply when:
1
2
3
4
the installed Meter has not been approved and / or verified, or
installed by the DSP;
the end User is Connected indirectly to the Distribution System;
i.e. by a privately owned network;
the metering of a building or complex has been divided to separate
Meters and independently provided Meters have been installed by
the building owner;
Meters are those installed at the boundary to the Transmission
System. In this scenario, the Saudi Arabian Grid Code will apply;
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5
MC.4
Meters are those installed by the DSP to measure power flow
throughout the network for system operation, monitoring and control
purposes.
METERING RESPONSIBILITY
DSPs shall be responsible for managing and collecting metering
information and shall ensure that all points on their Distribution Systems
identified as Connection Points have Meters.
The DSP shall provide a list of approved testing and calibration facilities
to any Meter Owner who requires those services.
Meter ownership
The Meter Owner is the person responsible for the Meter and the
Metering Equipment.
The DSP shall be the Meter Owner. The Meter Owner has responsibility
for ownership, purchase, maintenance, provide meters for calibration by
authorized third party and testing of the Meter and any Metering
Equipment.
Meter Access
The User has a responsibility to allow access to the Meter and any
Metering Equipment by the Meter Owner.
Meter and Metering Equipment
The term Meter, means the device that measures the amount of energy
produced or consumed.
Metering Equipment means any associated equipment at the
Connection Point and may consist of, but is not limited to
1
2
3
instrument transformers;
all interconnection electric/telecommunication cables, wires, and
devices, such as modems or antenna needed for the equipment to
operate correctly;
any metering cabinet.
Meter certification
Meters, including Smart Meters used in accordance with this Code shall
be approved types and comply with relevant Saudi standards. The DSP
shall maintain this list of approved Meters and shall make it available to
Users on request.All new Meters shall be required to undergo certification
tests, which shall be performed in accordance with the relevant SASO or
IEC standard.
Meter certificates shall be issued for a specified life span. The Meter
certificate duration may differ for different Meter types and may change
from time to time.
Following certification of a Meter, a certification seal will be applied. This
seal must be maintained intact in order for the Meter to retain certified
status.
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Meters removed from service must undergo re-certification test as set out
in this clause before reconnection for use.
New Meters shall have the capability of electronic data transfer.
Location of the Meter
Meters shall be installed as close to the Connection Point as is
reasonably practicable.
The actual location of the Meter is referred to as the “Metering Point”. This
may be different from the Connection Point. Where the Metering Point is
not coincident with the Connection Point, compensation shall be
provided for any power transformer and/or line losses so that the overall
accuracy requirement at the Connection Point is met.
MC.5
METER PARAMETERS
For each Connection Point, a Meter shall be installed, operated and
maintained to measure the following parameters;
Import and export Active Energy;
Import and Export Reactive Energy
The Meter shall be configured to record the peak Demand data for
each 30-minute period.
in the event of a power supply failure, the Meter shall protect all data
stored up to the time of the failure;
the clock, calendar and all data shall be supported for a period of
fifteen (15) days without an external supply Connected;
any "read" Operation shall not delete or alter any stored metered
data.
MC.5.1.1 Meter data storage
Data read from the Meter shall be maintained in a Metering Registration
System (MRS). The purpose of the MRS is to provide a complete,
accurate and up to date central database of all Meters and Meter data,
and to ensure an auditable trail to demonstrate compliance with this Code.
MC.5.1.1.1
Content of the MRS
The DSP shall create, maintain, and administer the MRS containing the
following information:
make and model of the meter
unique identifier of the Meter;
date of installation;
the date of commissioning of the Meter and commissioning
documents;
coordinates / location of the Meter;
the Meter Owner;
date of energization of the Meter;
the name of the person installing / testing the meter
fault, repair, and maintenance history for each Meter;
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MC.5.1.1.2
type of the Meter;
details of any Meter errors and any actions taken.
Minimum Requirements of the MRS
The MRS will provide at a minimum:
a storage capacity of forty eight (48) per day for a minimum of seven
years for all Active Power and Reactive Power values, Energy
Imports or Energy Exports through the Meter;
the stored Active Power and Reactive Power, Energy Imports to,
or Energy Exports through the Meter shall be integer values of kW
and kWh and have a resolution of at least 0.1% (at full load);
The DSP shall be the owner of all the metering data and shall keep
the data for at least seven years for audit trail purposes.
the DSP shall maintain the metering data for a minimum of seven
years after the replacement or disconnection of a Meter.
Access to Meter Data stored in the MRS
Data held in the MRS:
1
2
shall be the intellectual property of the DSP; and
may be accessed, free of charge by WERA and the User, but with
access limited to that Meter data directly associated with the Meter
of that User.
Meter data shall be maintained in line with current confidentiality
requirements.
MC.5.2.1 Meter records
The DSP shall ensure that complete and accurate records are maintained
of the verification and Operation of Meters. These records shall include
but not be limited to
the dates and results of any tests;
readings;
adjustments or inspection carried out and the dates on which any
seal was applied or broken;
the reasons for any seal being broken, and;
the person, undertaking tests, readings, inspections or sealing’s shall
be recorded.
Where the User is supplying the data, they shall ensure that the data is
provided promptly for entry into the MRS.
MC.6
OPERATION AND MAINTENANCE
Meters shall be operated and maintained in accordance with the
manufacturer’s and SASO recommendations so as to comply with its
obligations under this Code.
Meter responsibility
The DSP shall be responsible for ownership, purchase, maintenance and
testing of each Meter according to executive regulation of Metrology
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Law. The DSP is also responsible for managing and collecting metering
information and shall ensure that all Connection Points have a certified
Meter.
MC.6.1.1 Repair and maintenance of Meters and Metering Equipment
The Meter and any Metering Equipment shall be maintained by the DSP.
All test results, maintenance programmes, and sealing records shall be
kept for the life of the Meter. Once the equipment is retired, the records
must be kept for a minimum of six months. At the end of the six months
the records can be destroyed. The equipment data and test records shall
be made available on request to authorised parties.
MC.7
METERING STANDARDS
The accuracy, test arrangements and data exchange requirements of the
various items of Meters and Metering Equipment shall conform to one or
more of the applicable standards shown in Table 13.
SASO / IEC reference Title
ISO / IEC-17025
General requirements for the competence of testing and
calibration laboratories
ISO / IEC-17043
General requirements for proficiency testing
62052-11
Electricity Metering Equipment (AC) – general
requirements test and test conditions – Part 11:
Metering Equipment
62052-21
Electricity Metering Equipment (AC) – general
requirements test and text conditions – Part 21: tariff and
load control equipment
62053-22
Electricity Metering Equipment (AC) – static Meters for
active energy (classes 0.2 and 0.5)
62053-23
Electricity Metering Equipment (AC) – static Meters for
reactive energy (classes 2 and 3)
62056-1-0
Electricity metering data exchange – The DLMS/COSEM
suite – Part 1-0: Smart metering standardisation
framework
62056-21
Electricity metering - Data exchange for Meter reading,
tariff and load control – Direct local data exchange
62056-42
Electricity metering - Data exchange for Meter reading,
tariff and load control – Part 42: Physical layer services
and procedures for connection-oriented asynchronous
data exchange
62056-46
Electricity metering - Data exchange for Meter reading,
tariff and load control – Part 46: Data link layer using
HDLC protocol
62056-4-7
Electricity metering data exchange – The DLMS/
COSEM suite. Part4-7: DLMS / COSEM transport layer
for IP networks
62056-5-3
Electricity metering data exchange: The DLMS / COSEM
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suite – Part 5-3: DLMS / COSEM application layer
62056-6-1
Electricity metering data exchange – The DLMS /
COSEM suite – Part 6-2 COSEM interface classes
62056-6-2
Electricity metering – Data exchange for Meter reading,
tariff and load control – Interface classes
62058-11
Electricity Metering Equipment (AC) – Acceptance
inspection – Part 11: General acceptance inspection
methods
62058-21
Electricity Metering Equipment (AC) – Acceptance
inspection – Part 21: Particular requirements for
electromechanical Meters for active energy (classes 0,5,
1 and 2)
62053-21
Electricity metering equipment (a.c.) - Particular requirements
- Part 21: Static meters for active energy (classes 1 and 2)
SASO OIMLR46, 1
Active electrical energy meters – part 1; Metrological and
technical requirements
SASO OIMLR46, 2
Active electrical energy meters – part 2; Metrological
Controls and performance tests
SASO OIMLR46, 3
Active electrical energy meters – part 3: Test report
format
Table 13: Applicable SASO or IEC standards for metering
MC.8
ELECTRICITY METER CERTIFICATION
Meter approval and certification
The DSP shall confirm that Meters comply with the requirements of this
Metering Code and relevant Saudi Standards.
MC.8.1.1 Labelling of Meters
Each Meter shall be allocated a unique MIN that will be given by the DSP
and recorded in the MRS.
The MIN shall be marked permanently on the Meter in a position that is
clearly visible under all normal viewing of the Meter.
The MIN shall be quoted on all records arising from and related to the
Meter including Meter readings.
MC.8.1.2 Import and export convention
The following standard method of labelling Meters etc, based on the
definitions for import and export shall be incorporated. The required
labelling shall be as follows.
MC.8.1.2.1
Active Energy
“Import” for all Active Energy Flows normally leaving the Distribution
System, and
“Export” for all Active Energy Flows normally entering the Distribution
System,
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MC.8.1.2.2
Reactive Energy
Within the context of this code the relationship between Active Energy
and Reactive Energy can be best established by means of the Power
Factor. Table 14 gives the relationship.
Flow of Active Energy
Power Factor
Flow of Reactive Energy
Import
Lagging
Import
Import
Leading
Export
Import
Unity
Zero
Export
Lagging
Export
Export
Leading
Import
Export
Unity
zero
Table 14: Active / reactive energy convention
MC.8.1.3 Commissioning of Meters
Commissioning Tests shall be carried out on all new Meters Models in
QC environment before the Connection is made live and in accordance
with Good Industry Practice and the standards listed in MC.7.
Commissioning Tests shall be carried out before reconnection where a
replacement Meter is fitted. No Connection or reconnection shall be
permitted unless the tests are passed.
It is the responsibility of the Meter Owner to ensure that the
commissioning tests are completed before energisation.
The DSP is responsible for confirming that the Meter meets the
requirements of this code.
MC.9
PERIODIC CALIBRATION AND TESTING
Periodic calibration and testing of mechanical Meters shall be undertaken
as set out in this MC.9.
For electronic Meters, including Smart Meters, there is no provision for
adjustment after the manufacturing process and these Meters cannot be
adjusted. For the purposes of MC.9 an electronic Meter can only be
subject to initial verification (not calibrated) to ensure that it is within the
applicable standards.
The calibration period shall be no more than the limit set out in the ESPM
or the Metrology Law.
Meters shall also be tested outside of the prescribed intervals if the DSP
has reason to believe that the received Meter data is erroneous or the
Meter may have been tampered with.
In cases where an electronic Meter is outside the limits of error, the Meter
shall be replaced with a new Meter.
Reference Device
Any reference device used for electrical meter calibration must be
calibrated at the National Measurement Calibration Center at SASO.
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Meter Accuracy
The accuracy class of the Meter shall comply with SASO IEC 62053-22
IEC 62053-21 OIML R46 (active energy) and SASO IEC 62053-23
(reactive energy),
MC.9.2.1 Frequency of Testing
The frequency of testing shall be based on SASO requirements.
MC.9.2.2 Timekeeping
All Meters shall record time, based on Saudi Arabian Standard Time.
The commencement of each Demand period shall be within ±10 seconds
of the true time.
The duration of each Demand period shall be accurate to within ± 0.1%.
MC.9.2.3 Reference Device for Timekeeping
The reference devices for timekeeping must be calibrated at the National
Measurement Calibration Center at SASO.
MC.10
METER SEALS AND RIGHT OF ACCESS
All Meters and any associated communications equipment shall be
located in secure metering cabinets located in an area that is readily
accessible by the DSP and free from obstructions. The cabinets shall
include as a minimum, effective Protection from moisture and dust
ingress. The cabinets must be lockable to prevent unauthorized
access.Meter seals.
The seals on the Meter must be strong and durable, not prone to easy, or
accidental damage or early deterioration owing to weather or operating
environment.
The Meter seal shall display the required information by SASO.
Seals shall be designed and constructed to prevent undetectable
tampering under normal usage and must not permit their removal or
undoing without breaking.
The DSP shall seal the Meter and, if necessary the Metering Equipment.
Only the DSP personnel shall break DSP applied seals with authorization
by SASO.
Users shall be given at least forty-eight (48) hours' advance notice of the
breaking of seals on any part of the Meter. No such notice will be
necessary when the breaking of a seal in the case of an emergency.
Right of access
If the User is not the person who owns or controls the land on which the
Meter is situated, the User shall confirm that the DSP or their
representatives, have rights of access for metering purposes including
testing, calibration, maintenance and replacement of the Meter.
The right of access includes the right to bring any vehicles, Plant,
machinery and maintenance or other materials as shall be reasonably
necessary for the purposes of performance of obligations.
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MC.11
METER ERRORS
If any Meter is suspected of performing incorrectly, any affected party may
request accuracy test in accordance with Good Industry Practice to
confirm correct Operation and accuracy.
The party requesting the accuracy test shall bear the costs of such testing
if the Meter is found to be operating within the prescribed limits of error,
otherwise the cost of the accuracy test shall be borne by the Meter
Owner. All affected parties shall be given 24 hours’ notice of such tests
and be invited to witness the tests. Accuracy test results shall be made
available promptly and in writing to the affected parties.
When a test is requested, this shall commence within 15 working days
from the date of the request.
Meters shall normally be tested in service and should be tested out of
service only if the accuracy is not within the limits of the in-service test.
Certified test equipment and reference standards (all traceable to
recognised national standards (NMCC SASO)) shall be used in such tests
and if, by agreement, it is deemed necessary, an approved independent
laboratory may be employed.
All Meters shall comply with the relevant standards at the time that the
Meter Owner installs the Meter
Any errors shall be recorded before promptly adjusting, repairing or
renewing the Meter or replacing defective components. In such cases
substitute Meter data shall be provided in accordance with the DSP
procedures.
The Meter Owner shall replace or restore the Meter to service and prove
it to be operating within the prescribed limits of accuracy as soon as is
reasonably practicable. Upon the completion, examination, maintenance,
repair, recalibration or replacement of any component in the Meter, the
Meter shall be sealed.
Where a Meter error has occurred, this shall be recorded in the MRS.
MC.12
DAMAGE, TAMPERING OR INTERFERENCE
The DSP shall examine Meters periodically to ensure that all security
seals are intact and that the Meter is functioning properly and without any
signs of damage, tampering, or unauthorized interference.
In case such signs are evident, the DSP will investigate the matter further,
and if as a result, the integrity of the Meter or the Metering Equipment
becomes doubtful, the DSP will require the Meter or the Metering
Equipment to be replaced or repaired, as may be appropriate, at the cost
of the User. In either case, the Meter shall have to undergo testing,
certification, and calibration as is laid down in MC.9.
The DSP shall also deal with such issues of damage, tampering, and/or
unauthorized interference with the Meter in accordance with its standing
policy for handling such cases, which shall include, but not limited to, the
documenting of the situation and recording of evidence pertaining to
damage, tampering, and/or unauthorized interference;
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Where it is established that the Meter has been tampered or interfered
with, then until such tampering or interference has been rectified either;
the quantity measured or recorded shall be that measured or
recorded by any other relevant installed Meter; or
If there is no other relevant Meter or it is established to have been
tampered or interfered with, the quantity shall be agreed by the
parties, or, in the absence of such agreement, either party shall be
entitled to refer the matter to an expert for determination.
The DSP may decide to pursue any additional action against the User for
such unscrupulous acts in accordance with the applicable laws and/or
rules and regulations in the Kingdom.
Meter reconciliation
The DSP shall arrange to read the energy values every month for all
Meters.
If energy values are not available remotely, then the DSP will take manual
readings each month for the above purposes.
If any difference between the manual reading and electronically recorded
reading of more than 0.1 percent is noticed, it shall be highlighted and
referred for further checking.
If as a result of the above check, the discrepancy is confirmed, then the
DSP will inform the relevant User and take appropriate action to deal with
the situation in accordance with the provisions of MC.11.
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