THE GRID CODE - National Grid

THE GRID CODE - National Grid
THE GRID CODE
ISSUE 5
REVISION 21
21 March 2017
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1.
to the extent that any party who is required to comply (or is exempt from complying) with the provisions
under the Electricity Act 1989 reasonably needs to reproduce this publication to undertake its licence or
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2.
in accordance with the provisions of the Copyright, Designs and Patents Act 1988.
THE GRID CODE
CONTENTS
CONTENTS*
(C)
PREFACE*
(P)
GLOSSARY AND DEFINITIONS
(GD)
PLANNING CODE
(PC)
CONNECTION CONDITIONS
(CC)
COMPLIANCE PROCESSES
(CP)
OPERATING CODES
(OC)
OC1
Demand Forecasts
OC2
Operational Planning and Data Provision
OC3
Not Used
OC4
Not Used
OC5
Testing and Monitoring
OC6
Demand Control
OC7
Operational Liaison
OC8
Safety Co-ordination
OC9
Contingency Planning
OC10 Event Information Supply
OC11 Numbering and Nomenclature of HV Apparatus at Certain Sites
OC12 System Tests
BALANCING CODES
BC1
Pre Gate Closure Process
BC2
Post Gate Closure Process
BC3
Frequency Control Process
(BC)
DATA REGISTRATION CODE
(DRC)
GENERAL CONDITIONS
(GC)
GOVERNANCE RULES
(GR)
REVISIONS*
(R)
*does not constitute part of the Grid Code
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PREFACE
(P)
(This section does not form part of the Grid Code)
P.1.
The Grid Code sets out the operating procedures and principles governing the relationship
between NGET and all Users of the National Electricity Transmission System, be they
Generators, DC Converter owners, Suppliers or Non-Embedded Customers. The Grid
Code specifies day-to-day procedures for both planning and operational purposes and covers
both normal and exceptional circumstances.
P.2
The Grid Code is designed to:
(i)
permit the development, maintenance and operation of an efficient, coordinated and
economical system for the transmission of electricity;
(ii)
facilitate competition in the generation and supply of electricity (and without limiting the
foregoing, to facilitate the national electricity transmission system being made available
to persons authorised to supply or generate electricity on terms which neither prevent
nor restrict competition in the supply or generation of electricity);
(iii) promote the security and efficiency of the electricity generation, transmission and
distribution systems in the national electricity transmission system operator area taken
as a whole; and
(iv) efficiently discharge the obligations imposed upon the licensee by this license and to
comply with the Electricity Regulation and any relevant legally binding decisions of the
European Commission and/or the Agency.
and is conceived as a statement of what is optimal (particularly from a technical point of view)
for all Users and NGET itself in relation to the planning, operation and use of the National
Electricity Transmission System. It seeks to avoid any undue discrimination between
Users and categories of Users.
P.3
The Grid Code is divided into the following sections:
(a) a Planning Code which provides generally for the supply of certain information by
Users in order for NGET to undertake the planning and development of the National
Electricity Transmission System;
(b) the Connection Conditions which specify minimum technical, design and operational
criteria which must be complied with by NGET at Connection Sites and by Users
connected to or seeking connection with the National Electricity Transmission
System or by Generators (other than in respect of Small Power Stations) or DC
Converter owners, connected to or seeking connection to a User's System;
(c) the Compliance Processes which specify the process that must be followed by NGET
and any Generator or DC Converter Station owner to demonstrate its compliance with
the Grid Code in relation to its Plant and Apparatus.
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(d) an Operating Code, which is split into a number of sections and deals with Demand
forecasting (OC1); the co-ordination of the outage planning process in respect of Large
Power Stations, the National Electricity Transmission System and User Systems
for construction, repair and maintenance, and the provision of certain types of
Operating Margin data (OC2); testing and monitoring of Users (OC5); different forms
of reducing Demand (OC6); the reporting of scheduled and planned actions, and
unexpected occurrences such as faults (OC7); the co-ordination, establishment and
maintenance of Isolation and Earthing in order that work and/or testing can be carried
out safely (OC8); certain aspects of contingency planning (OC9); the provision of written
reports on occurrences such as faults in certain circumstances (OC10); the procedures
for numbering and nomenclature of HV Apparatus at certain sites (OC11); and the
procedures for the establishment of System Tests (OC12);
(e) a Balancing Code, which is split into three sections and deals with the submission of
BM Unit Data from BM Participants, and of certain other information, for the following
day and ahead of Gate Closure (BC1); the post Gate Closure process (BC2); and the
procedures and requirements in relation to System Frequency control (BC3);
(f)
a Data Registration Code, which sets out a unified listing of all data required by NGET
from Users, and by Users from NGET, under the Grid Code;
(g) General Conditions, which are intended to ensure, so far as possible, that the various
sections of the Grid Code work together and work in practice and include provisions
relating to the establishment of a Grid Code Review Panel and other provisions of a
general nature.
P.4
This Preface is provided to Users and to prospective Users for information only and does not
constitute part of the Grid Code.
< END OF PREFACE >
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GD.2
Construction of References
GD.2.1
In the Grid Code:
(i)
a table of contents, a Preface, a Revision section, headings, and the Appendix to this
Glossary and Definitions are inserted for convenience only and shall be ignored in
construing the Grid Code;
(ii)
unless the context otherwise requires, all references to a particular paragraph, subparagraph, Appendix or Schedule shall be a reference to that paragraph, sub-paragraph
Appendix or Schedule in or to that part of the Grid Code in which the reference is made;
(iii) unless the context otherwise requires, the singular shall include the plural and vice
versa, references to any gender shall include all other genders and references to
persons shall include any individual, body corporate, corporation, joint venture, trust,
unincorporated association, organisation, firm or partnership and any other entity, in
each case whether or not having a separate legal personality;
(iv) references to the words "include" or "including" are to be construed without limitation to
the generality of the preceding words;
(v) unless there is something in the subject matter or the context which is inconsistent
therewith, any reference to an Act of Parliament or any Section of or Schedule to, or
other provision of an Act of Parliament shall be construed at the particular time, as
including a reference to any modification, extension or re-enactment thereof then in
force and to all instruments, orders and regulations then in force and made under or
deriving validity from the relevant Act of Parliament;
(vi) where the Glossary and Definitions refers to any word or term which is more
particularly defined in a part of the Grid Code, the definition in that part of the Grid Code
will prevail (unless otherwise stated) over the definition in the Glossary & Definitions in
the event of any inconsistency;
(vii) a cross-reference to another document or part of the Grid Code shall not of itself impose
any additional or further or co-existent obligation or confer any additional or further or
co-existent right in the part of the text where such cross-reference is contained;
(viii) nothing in the Grid Code is intended to or shall derogate from NGET's statutory or
licence obligations;
(ix) a "holding company" means, in relation to any person, a holding company of such
person within the meaning of section 736, 736A and 736B of the Companies Act 1985
as substituted by section 144 of the Companies Act 1989 and, if that latter section is not
in force at the Transfer Date, as if such latter section were in force at such date;
(x) a "subsidiary" means, in relation to any person, a subsidiary of such person within the
meaning of section 736, 736A and 736B of the Companies Act 1985 as substituted by
section 144 of the Companies Act 1989 and, if that latter section is not in force at the
Transfer Date, as if such latter section were in force at such date;
(xi) references to time are to London time; and
(xii) (a) Save where (b) below applies, where there is a reference to an item of data being
expressed in a whole number of MW, fractions of a MW below 0.5 shall be rounded
down to the nearest whole MW and fractions of a MW of 0.5 and above shall be
rounded up to the nearest whole MW;
(b) In the case of the definition of Registered Capacity, fractions of a MW below 0.05
shall be rounded down to one decimal place and fractions of a MW of 0.05 and above
shall be rounded up to one decimal place.
< END OF GLOSSARY & DEFINITIONS >
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GLOSSARY & DEFINITIONS
(GD)
GD.1
In the Grid Code the following words and expressions shall, unless the subject matter or
context otherwise requires or is inconsistent therewith, bear the following meanings:
Access Group
A group of Connection Points within which a User declares under the
Planning Code
(a)
An interconnection and/or
(b)
A need to redistribute Demand between those Connection Points
either pre-fault or post-fault
Where a single Connection Point does not form part of an Access
Group in accordance with the above, that single Connection Point shall
be considered to be an Access Group in its own right.
Access Period
A period of time in respect of which each Transmission Interface
Circuit is to be assessed as whether or not it is capable of being
maintained as derived in accordance with PC.A.4.1.4. The period shall
commence and end on specified calendar weeks.
Act
The Electricity Act 1989 (as amended by the Utilities Act 2000 and the
Energy Act 2004).
Active Energy
The electrical energy produced, flowing or supplied by an electric circuit
during a time interval, being the integral with respect to time of the
instantaneous power, measured in units of watt-hours or standard
multiples thereof, ie:
1000 Wh = 1 kWh
1000 kWh = 1 MWh
1000 MWh = 1 GWh
1000 GWh = 1 TWh
Active Power
The product of voltage and the in-phase component of alternating current
measured in units of watts and standard multiples thereof, ie:
1000 Watts = 1 kW
1000 kW = 1 MW
1000 MW = 1 GW
1000 GW = 1 TW
Affiliate
In relation to any person, any holding company or subsidiary of such
person or any subsidiary of a holding company of such person, in each
case within the meaning of Section 736, 736A and 736B of the
Companies Act 1985 as substituted by section 144 of the Companies Act
1989 and, if that latter section is not in force at the Transfer Date, as if
such section were in force at such date.
AF Rules
Has the meaning given to “allocation framework” in section 13(2) of the
Energy Act 2013.
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Agency
As defined in the Transmission Licence.
Alternate Member
Shall mean an alternate member for the Panel Members elected or
appointed in accordance with this GR.7.2(a) or (b).
Ancillary Service
A System Ancillary Service and/or a Commercial Ancillary Service,
as the case may be.
Ancillary Services
Agreement
An agreement between a User and NGET for the payment by NGET to
that User in respect of the provision by such User of Ancillary Services.
Annual Average Cold
Spell Conditions or ACS
Conditions
A particular combination of weather elements which gives rise to a level
of peak Demand within a Financial Year which has a 50% chance of
being exceeded as a result of weather variation alone.
Apparent Power
The product of voltage and of alternating current measured in units of
voltamperes and standard multiples thereof, ie:
1000 VA = 1 kVA
1000 kVA = 1 MVA
Apparatus
Other than in OC8, means all equipment in which electrical conductors
are used, supported or of which they may form a part. In OC8 it means
High Voltage electrical circuits forming part of a System on which
Safety Precautions may be applied to allow work and/or testing to be
carried out on a System.
Approved Fast Track
Proposal
Has the meaning given in GR.26.7, provided that no objection is received
pursuant to GR.26.12.
Approved Grid Code
Self-Governance
Proposal
Has the meaning given in GR.24.10.
Approved Modification
Has the meaning given in GR.22.7
Authorised Electricity
Operator
Any person (other than NGET in its capacity as operator of the National
Electricity Transmission System) who is authorised under the Act to
generate, participate in the transmission of, distribute or supply electricity
which shall include any Interconnector Owner or Interconnector User..
Authority-Led
Modification
A Grid Code Modification Proposal in respect of a Significant Code
Review, raised by the Authority pursuant to GR.17
Authority-Led
Modification Report
Has the meaning given in GR.17.4.
Automatic Voltage
Regulator or AVR
The continuously acting automatic equipment controlling the terminal
voltage of a Synchronous Generating Unit by comparing the actual
terminal voltage with a reference value and controlling by appropriate
means the output of an Exciter, depending on the deviations.
Authority for Access
An authority which grants the holder the right to unaccompanied access
to sites containing exposed HV conductors.
Authority, The
The Authority established by section 1 (1) of the Utilities Act 2000.
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Auxiliaries
Any item of Plant and/or Apparatus not directly a part of the boiler plant
or Generating Unit or DC Converter or Power Park Module, but
required for the boiler plant's or Generating Unit's or DC Converter’s or
Power Park Module’s functional operation.
Auxiliary Diesel Engine
A diesel engine driving a Generating Unit which can supply a Unit
Board or Station Board, which can start without an electrical power
supply from outside the Power Station within which it is situated.
Auxiliary Gas Turbine
A Gas Turbine Unit, which can supply a Unit Board or Station Board,
which can start without an electrical power supply from outside the
Power Station within which it is situated.
Average Conditions
That combination of weather elements within a period of time which is the
average of the observed values of those weather elements during
equivalent periods over many years (sometimes referred to as normal
weather).
Back-Up Protection
A Protection system which will operate when a system fault is not
cleared by other Protection.
Balancing and
Settlement Code or BSC
The code of that title as from time to time amended.
Balancing Code or BC
That portion of the Grid Code which specifies the Balancing Mechanism
process.
Balancing Mechanism
Has the meaning set out in NGET’s Transmission Licence
Balancing Mechanism
Reporting Agent or
BMRA
Has the meaning set out in the BSC.
Balancing Mechanism
Reporting Service or
BMRS
Has the meaning set out in the BSC.
Balancing Principles
Statement
A statement prepared by NGET in accordance with Condition C16 of
NGET’s Transmission Licence.
Baseline Forecast
Has the meaning given to the term ‘baseline forecase’ in Section G of the
BSC.
Bid-Offer Acceptance
(a)
A communication issued by NGET in accordance with BC2.7; or
(b)
an Emergency Instruction to the extent provided for in BC2.9.2.3.
Bid-Offer Data
Has the meaning set out in the BSC.
Bilateral Agreement
Has the meaning set out in the CUSC
Black Start
The procedure necessary for a recovery from a Total Shutdown or
Partial Shutdown.
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Black Start Capability
An ability in respect of a Black Start Station, for at least one of its
Gensets to Start-Up from Shutdown and to energise a part of the
System and be Synchronised to the System upon instruction from
NGET, within two hours, without an external electrical power supply.
Black Start Stations
Power Stations which are registered, pursuant to the Bilateral
Agreement with a User, as having a Black Start Capability.
Black Start Test
A Black Start Test carried out by a Generator with a Black Start
Station, on the instructions of NGET, in order to demonstrate that a
Black Start Station has a Black Start Capability.
Block Load Capability
The incremental Active Power steps, from no load to Rated MW, which
a generator can instantaneously supply without causing it to trip or go
outside the Frequency range of 47.5 – 52Hz (or an otherwise agreed
Frequency range). The time between each incremental step shall also
be provided.
BM Participant
A person who is responsible for and controls one or more BM Units or
where a Bilateral Agreement specifies that a User is required to be
treated as a BM Participant for the purposes of the Grid Code. For the
avoidance of doubt, it does not imply that they must be active in the
Balancing Mechanism.
BM Unit
Has the meaning set out in the BSC, except that for the purposes of the
Grid Code the reference to “Party” in the BSC shall be a reference to
User.
BM Unit Data
The collection of parameters associated with each BM Unit, as described
in Appendix 1 of BC1.
Boiler Time Constant
Determined at Registered Capacity, the boiler time constant will be
construed in accordance with the principles of the IEEE Committee
Report "Dynamic Models for Steam and Hydro Turbines in Power System
Studies" published in 1973 which apply to such phrase.
British Standards or BS
Those standards and specifications approved by the British Standards
Institution.
BSCCo
Has the meaning set out in the BSC.
BSC Panel
Has meaning set out for “Panel” in the BSC.
BS Station Test
A Black Start Test carried out by a Generator with a Black Start
Station while the Black Start Station is disconnected from all external
alternating current electrical supplies.
BS Unit Test
A Black Start Test carried out on a Generating Unit or a CCGT Unit, as
the case may be, at a Black Start Station while the Black Start Station
remains connected to an external alternating current electrical supply.
Business Day
Any week day (other than a Saturday) on which banks are open for
domestic business in the City of London.
Cancellation of National
Electricity Transmission
System Warning
The notification given to Users when a National Electricity
Transmission System Warning is cancelled.
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Capacity Market
Documents
The Capacity Market Rules, The Electricity Capacity Regulations 2014
and any other Regulations made under Chapter 3 of Part 2 of the Energy
Act 2013 which are in force from time to time.
Capacity Market Rules
The rules made under section 34 of the Energy Act 2013 as modified
from time to time in accordance with that section and The Electricity
Capacity Regulations 2014.
Cascade Hydro Scheme
Two or more hydro-electric Generating Units, owned or controlled by the
same Generator, which are located in the same water catchment area
and are at different ordnance datums and which depend upon a common
source of water for their operation, known as:
(a)
Moriston
(b)
Killin
I
Garry
(d)
Conon
(e)
Clunie
(f)
Beauly
which will comprise more than one Power Station.
Cascade Hydro Scheme
Matrix
The matrix described in Appendix 1 to BC1 under the heading Cascade
Hydro Scheme Matrix.
Caution Notice
A notice conveying a warning against interference.
Category 1 Intertripping
Scheme
A System to Generator Operational Intertripping Scheme arising from
a Variation to Connection Design following a request from the relevant
User which is consistent with the criteria specified in the Security and
Quality of Supply Standard.
Category 2 Intertripping
Scheme
A System to Generator Operational Intertripping Scheme which is: (i)
required to alleviate an overload on a circuit which connects the
Group containing the User’s Connection Site to the National
Electricity Transmission System; and
(ii)
installed in accordance with the requirements of the planning
criteria of the Security and Quality of Supply Standard in order
that measures can be taken to permit maintenance acc ess for
each transmission circuit and for such measures to be
economically justified,
and the operation of which results in a reduction in Active Power on the
overloaded circuits which connect the User’s Connection Site to the
rest of the National Electricity Transmission System which is equal to
the reduction in Active Power from the Connection Site (once any
system losses or third party system effects are discounted).
Category 3 Intertripping
Scheme
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A System to Generator Operational Intertripping Scheme which,
where agreed by NGET and the User, is installed to alleviate an overload
on, and as an alternative to, the reinforcement of a third party system,
such as the Distribution System of a Public Distribution System
Operator.
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Category 4 Intertripping
Scheme
A System to Generator Operational Intertripping Scheme installed to
enable the disconnection of the Connection Site from the National
Electricity Transmission System in a controlled and efficient manner in
order to facilitate the timely restoration of the National Electricity
Transmission System.
CENELEC
European Committee for Electrotechnical Standardisation.
Citizens Advice
Means the National Association of Citizens Advice
Bureaux.
Citizens Advice
Scotland
Means the Scottish Association of Citizens Advice
CfD Counterparty
A person designated as a “CfD counterparty” under section 7(1) of the
Energy Act 2013.
CfD Documents
The AF Rules, The Contracts for Difference (Allocation) Regulations
2014, The Contracts for Difference (Definition of Eligible Generator)
Regulations 2014 and The Contracts for Difference (Electricity Supplier
Obligations) Regulations 2014 and any other regulations made under
Chapter 2 of Part 2 of the Energy Act 2013 which are in force from time
to time.
Bureaux.
CfD Settlement Services means any person:
Provider
(i)
appointed for the time being and from time to time by a CfD
Counterparty; or
(ii)
who is designated by virtue of Section C1.2.1B of the
Balancing and Settlement Code,
in either case to carry out any of the CFD settlement activities (or any
successor entity performing CFD settlement activities).
CCGT Module Matrix
The matrix described in Appendix 1 to BC1 under the heading CCGT
Module Matrix.
CCGT Module Planning
Matrix
A matrix in the form set out in Appendix 3 of OC2 showing the
combination of CCGT Units within a CCGT Module which would be
running in relation to any given MW output.
CM Administrative
Parties
The Secretary of State, the CM Settlement Body, and any CM
Settlement Services Provider.
CM Settlement Body
the Electricity Settlements Company Ltd or such other person as may
from time to time be appointed as Settlement Body under regulation 80 of
the Electricity Capacity Regulations 2014.
CM Settlement Services
Provider
any person with whom the CM Settlement Body has entered into a
contract to provide services to it in relation to the performance of its
functions under the Capacity Market Documents.
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Code Administration
Code of Practice
Code Administrator
Means the code of practice approved by the Authority and:
(a)
developed and maintained by the code administrators in existence
from time to time; and
(b)
amended subject to the Authority’s approval from time to time;
and
(c)
re-published from time to time;
Means NGET carrying out the role of Code Administrator in accordance
with the General Conditions.
Combined Cycle Gas
Turbine Module or
CCGT Module
A collection of Generating Units (registered as a CCGT Module under
the PC) comprising one or more Gas Turbine Units (or other gas based
engine units) and one or more Steam Units where, in normal operation,
the waste heat from the Gas Turbines is passed to the water/steam
system of the associated Steam Unit or Steam Units and where the
component units within the CCGT Module are directly connected by
steam or hot gas lines which enable those units to contribute to the
efficiency of the combined cycle operation of the CCGT Module.
Combined Cycle Gas
Turbine Unit or CCGT
Unit
A Generating Unit within a CCGT Module.
Commercial Ancillary
Services
Ancillary Services, other than System Ancillary Services, utilised by
NGET in operating the Total System if a User (or other person) has
agreed to provide them under an Ancillary Services Agreement or
under a Bilateral Agreement with payment being dealt with under an
Ancillary Services Agreement or in the case of Externally
Interconnected System Operators or Interconnector Users, under
any other agreement (and in the case of Externally Interconnected
System Operators and Interconnector Users includes ancillary
services equivalent to or similar to System Ancillary Services).
Commercial Boundary
Has the meaning set out in the CUSC
Committed Project
Planning Data
Data relating to a User Development once the offer for a CUSC
Contract is accepted.
Common Collection
Busbar
A busbar within a Power Park Module to which the higher voltage side
of two or more Power Park Unit generator transformers are connected.
Completion Date
Has the meaning set out in the Bilateral Agreement with each User to
that term or in the absence of that term to such other term reflecting the
date when a User is expected to connect to or start using the National
Electricity Transmission System. In the case of an Embedded
Medium Power Station or Embedded DC Converter Station having a
similar meaning in relation to the Network Operator’s System as set out
in the Embedded Development Agreement.
Complex
A Connection Site together with the associated Power Station and/or
Network Operator substation and/or associated Plant and/or
Apparatus, as appropriate.
Compliance Processes
or CP
That portion of the Grid Code which is identified as the Compliance
Processes.
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Compliance Statement
A statement completed by the relevant User confirming compliance with
each of the relevant Grid Code provisions, and the supporting evidence
in respect of such compliance, of its:
Generating Unit(s); or,
CCGT Module(s); or,
Power Park Module(s); or,
DC Converter(s)
in the form provided by NGET to the relevant User or another format as
agreed between the User and NGET.
Connection Conditions
or CC
That portion of the Grid Code which is identified as the Connection
Conditions.
Connection Entry
Capacity
Has the meaning set out in the CUSC
Connected Planning
Data
Data which replaces data containing estimated values assumed for
planning purposes by validated actual values and updated estimates for
the future and by updated forecasts for Forecast Data items such as
Demand.
Connection Point
A Grid Supply Point or Grid Entry Point, as the case may be.
Connection Site
A Transmission Site or User Site, as the case may be.
Construction
Agreement
Has the meaning set out in the CUSC
Consumer
Representative
Means the person appointed by the Citizens Advice or the Citizens
Advice Scotland (or any successor body) representing all categories of
customers, appointed in accordance with GR.4.2(b)
Contingency Reserve
The margin of generation over forecast Demand which is required in the
period from 24 hours ahead down to real time to cover against
uncertainties in Large Power Station availability and against both
weather forecast and Demand forecast errors.
Control Calls
A telephone call whose destination and/or origin is a key on the control
desk telephone keyboard at a Transmission Control Centre and which,
for the purpose of Control Telephony, has the right to exercise priority
over (ie. disconnect) a call of a lower status.
Control Centre
A location used for the purpose of control and operation of the National
Electricity Transmission System or DC Converter Station owner's
System or a User System other than a Generator's System or an
External System.
Control Engineer
A person nominated by the relevant party for the control of its Plant and
Apparatus.
Control Person
The term used as an alternative to "Safety Co-ordinator" on the Site
Responsibility Schedule only.
Control Phase
The Control Phase follows on from the Programming Phase and
covers the period down to real time.
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Control Point
The point from which:(a)
A Non-Embedded Customer's Plant and Apparatus is
controlled; or
(b)
A BM Unit at a Large Power Station or at a Medium Power
Station or representing a Cascade Hydro Scheme or with a
Demand Capacity with a magnitude of:
(i)
50MW or more in NGET’s Transmission Area; or
(ii)
30MW or more in SPT’s Transmission Area; or
(iii)
10MW or more in SHETL’s Transmission Area,
(iv)
10MW or more which is connected to an Offshore
Transmission System
is physically controlled by a BM Participant; or
(c)
In the case of any other BM Unit or Generating Unit, data
submission is co-ordinated for a BM Participant and instructions
are received from NGET,
as the case may be. For a Generator this will normally be at a Power
Station but may be at an alternative location agreed with NGET. In the
case of a DC Converter Station, the Control Point will be at a location
agreed with NGET. In the case of a BM Unit of an Interconnector User,
the Control Point will be the Control Centre of the relevant Externally
Interconnected System Operator.
Control Telephony
The principal method by which a User's Responsible
Engineer/Operator and NGET Control Engineer(s) speak to one
another for the purposes of control of the Total System in both normal
and emergency operating conditions.
Core Industry Document
as defined in the Transmission Licence
Core Industry Document
Owner
In relation to a Core Industry Document, the body(ies) or entity(ies)
responsible for the management and operation of procedures for making
changes to such document
CUSC
Has the meaning set out in NGET’s Transmission Licence
CUSC Contract
One or more of the following agreements as envisaged in Standard
Condition C1 of NGET’s Transmission Licence:
(a)
the CUSC Framework Agreement;
(b)
a Bilateral Agreement;
(c)
a Construction Agreement
or a variation to an existing Bilateral Agreement and/or Construction
Agreement;
CUSC Framework
Agreement
Has the meaning set out in NGET’s Transmission Licence
CUSC Party
As defined in the Transmission Licence and “CUSC Parties” shall be
construed accordingly.
Customer
A person to whom electrical power is provided (whether or not he is the
same person as the person who provides the electrical power).
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Customer Demand
Management
Reducing the supply of electricity to a Customer or disconnecting a
Customer in a manner agreed for commercial purposes between a
Supplier and its Customer.
Customer Demand
Management
Notification Level
The level above which a Supplier has to notify NGET of its proposed or
achieved use of Customer Demand Management which is 12 MW in
England and Wales and 5 MW in Scotland.
Customer Generating
Plant
A Power Station or Generating Unit of a Customer to the extent that it
operates the same exclusively to supply all or part of its own electricity
requirements, and does not export electrical power to any part of the
Total System.
Data Registration Code
or DRC
That portion of the Grid Code which is identified as the Data
Registration Code.
Data Validation,
Consistency and
Defaulting Rules
The rules relating to validity and consistency of data, and default data to
be applied, in relation to data submitted under the Balancing Codes, to
be applied by NGET under the Grid Code as set out in the document
“Data Validation, Consistency and Defaulting Rules” - Issue 8, dated 25th
January 2012. The document is available on the National Grid website or
upon request from NGET.
DC Converter
Any Onshore DC Converter or Offshore DC Converter.
DC Converter Station
An installation comprising one or more Onshore DC Converters
connecting a direct current interconnector:
to the NGET Transmission System; or,
(if the installation has a rating of 50MW or more) to a User System,
and it shall form part of the External Interconnection to which it relates.
DC Network
All items of Plant and Apparatus connected together on the direct
current side of a DC Converter.
DCUSA
The Distribution Connection and Use of System Agreement approved by
the Authority and required to be maintained in force by each Electricity
Distribution Licence holder.
De-Load
The condition in which a Genset has reduced or is not delivering
electrical power to the System to which it is Synchronised.
Demand
The demand of MW and Mvar of electricity (i.e. both Active and
Reactive Power), unless otherwise stated.
Demand Capacity
Has the meaning as set out in the BSC.
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Demand Control
Any or all of the following methods of achieving a Demand reduction:
(a)
Customer voltage reduction initiated by Network Operators
(other than following an instruction from NGET);
(b)
Customer Demand reduction by Disconnection initiated by
Network Operators (other than following an instruction from
NGET);
(c)
Demand reduction instructed by NGET;
(d)
automatic low Frequency Demand Disconnection;
(e)
emergency manual Demand Disconnection.
Demand Control
Notification Level
The level above which a Network Operator has to notify NGET of its
proposed or achieved use of Demand Control which is 12 MW in
England and Wales and 5 MW in Scotland.
Designed Minimum
Operating Level
The output (in whole MW) below which a Genset or a DC Converter at a
DC Converter Station (in any of its operating configurations) has no
High Frequency Response capability.
De-Synchronise
(a)
The act of taking a Generating Unit, Power Park Module or DC
Converter off a System to which it has been Synchronised, by
opening any connecting circuit breaker; or
(b)
The act of ceasing to consume electricity at an importing BM Unit;
and the term "De-Synchronising" shall be construed accordingly.
De-synchronised
Island(s)
Has the meaning set out in OC9.5.1(a)
Detailed Planning Data
Detailed additional data which NGET requires under the PC in support of
Standard Planning Data, comprising DPD I and DPD II
Detailed Planning Data
Category I or DPD I
The Detailed Planning Data categorised as such in the DRC, and
submitted in accordance with PC.4.4.2 or PC.4.4.4 as applicable.
Detailed Planning Data
Category II or DPD II
The Detailed Planning Data categorised as such in the DRC, and
submitted in accordance with PC.4.4.2 or PC.4.4.4 as applicable.
Discrimination
The quality where a relay or protective system is enabled to pick out and
cause to be disconnected only the faulty Apparatus.
Disconnection
The physical separation of Users (or Customers) from the National
Electricity Transmission System or a User System as the case may
be.
Disputes Resolution
Procedure
The procedure described in the CUSC relating to disputes resolution.
Distribution Code
The distribution code required to be drawn up by each Electricity
Distribution Licence holder and approved by the Authority, as from
time to time revised with the approval of the Authority.
Droop
The ratio of the per unit steady state change in speed, or in Frequency
to the per unit steady state change in power output.
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Dynamic Parameters
Those parameters listed in Appendix 1 to BC1 under the heading BM
Unit Data – Dynamic Parameters.
E&W Offshore
Transmission System
An Offshore Transmission System with an Interface Point in England
and Wales.
E&W Offshore
Transmission Licensee
A person who owns or operates an E&W Offshore Transmission
System pursuant to a Transmission Licence.
E&W Transmission
System
Collectively NGET’s Transmission System and any E&W Offshore
Transmission Systems.
E&W User
A User in England and Wales or any Offshore User who owns or
operates Plant and/or Apparatus connected (or which will at the OTSUA
Transfer Time be connected) to an E&W Offshore Transmission
System.
Earth Fault Factor
At a selected location of a three-phase System (generally the point of
installation of equipment) and for a given System configuration, the ratio
of the highest root mean square phase-to-earth power Frequency
voltage on a sound phase during a fault to earth (affecting one or more
phases at any point) to the root mean square phase-to-earth power
Frequency voltage which would be obtained at the selected location
without the fault.
Earthing
A way of providing a connection between conductors and earth by an
Earthing Device which is either:
(a)
Immobilised and Locked in the earthing position. Where the
Earthing Device is Locked with a Safety Key, the Safety Key
must be secured in a Key Safe and the Key Safe Key must be,
where reasonably practicable, given to the authorised site
representative of the Requesting Safety Co-ordinator and is to
be retained in safe custody. Where not reasonably practicable the
Key Safe Key must be retained by the authorised site
representative of the Implementing Safety Co-ordinator in safe
custody; or
(b)
maintained and/or secured in position by such other method which
must be in accordance with the Local Safety Instructions of
NGET or the Safety Rules of the Relevant Transmission
Licensee or that User, as the case may be.
Earthing Device
A means of providing a connection between a conductor and earth being
of adequate strength and capability.
Elected Panel Members
Shall mean the following Panel Members elected in accordance with
GR4.2(a):
(a) the representative of the Suppliers;
(b) the representative of the Onshore Transmission Licensees;
(c) the representative of the Offshore Transmission Licensees; and
(d) the representatives of the Generators
Electrical Standard
A standard listed in the Annex to the General Conditions.
Electricity Council
That body set up under the Electricity Act, 1957.
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Electricity Distribution
Licence
The licence granted pursuant to Section 6(1) (c) of the Act.
Electricity Regulation
As defined in the Transmission Licence.
Electricity Supply
Industry Arbitration
Association
The unincorporated members' club of that name formed inter alia to
promote the efficient and economic operation of the procedure for the
resolution of disputes within the electricity supply industry by means of
arbitration or otherwise in accordance with its arbitration rules.
Electricity Supply
Licence
The licence granted pursuant to Section 6(1) (d) of the Act.
Electromagnetic
Compatibility Level
Has the meaning set out in Engineering Recommendation G5/4.
Embedded
Having a direct connection to a User System or the System of any other
User to which Customers and/or Power Stations are connected, such
connection being either a direct connection or a connection via a busbar
of another User or of a Transmission Licensee (but with no other
connection to the National Electricity Transmission System).
Embedded Development
Has the meaning set out in PC.4.4.3(a)
Embedded Development
Agreement
An agreement entered into between a Network Operator and an
Embedded Person, identifying the relevant site of connection to the
Network Operator’s System and setting out other site specific details in
relation to that use of the Network Operator’s System.
Embedded Person
The party responsible for a Medium Power Station not subject to a
Bilateral Agreement or DC Converter Station not subject to a Bilateral
Agreement connected to or proposed to be connected to a Network
Operator’s System.
Emergency
Deenergisation
Instruction
an Emergency Instruction issued by NGET to De-Synchronise a
Generating Unit, Power Park Module or DC Converter in
circumstances specified in the CUSC.
Emergency Instruction
An instruction issued by NGET in emergency circumstances, pursuant to
BC2.9, to the Control Point of a User. In the case of such instructions
applicable to a BM Unit, it may require an action or response which is
outside the Dynamic Parameters, QPN or Other Relevant Data, and
may include an instruction to trip a Genset.
EMR Administrative
Parties
Has the meaning given to “administrative parties” in The Electricity
Capacity Regulations 2014 and each CfD Counterparty and CfD
Settlement Services Provider.
EMR Documents
The Energy Act 2013, The Electricity Capacity Regulations 2014, the
Capacity Market Rules, The Contracts for Difference (Allocation)
Regulations 2014, The Contracts for Difference (Definition of Eligible
Generator) Regulations 2014, The Contracts for Difference (Electricity
Supplier Obligations) Regulations 2014, The Electricity Market Reform
(General) Regulations 2014, the AF Rules and any other regulations or
instruments made under Chapter 2 (contracts for difference), Chapter 3
(capacity market) or Chapter 4 (investment contracts) of Part 2 of the
Energy Act 2013 which are in force from time to time.
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EMR Functions
Has the meaning given to “EMR functions” in Chapter 5 of Part 2 of the
Energy Act 2013.
Engineering
Recommendations
The documents referred to as such and issued by the Energy Networks
Association or the former Electricity Council.
Energisation
Operational Notification
or EON
A notification (in respect of Plant and Apparatus (including OTSUA)
which is directly connected to the National Electricity Transmission
System) from NGET to a User confirming that the User can in
accordance with the Bilateral Agreement and/or Construction
Agreement, energise such User’s Plant and Apparatus (including
OTSUA) specified in such notification.
Estimated Registered
Data
Those items of Standard Planning Data and Detailed Planning Data
which either upon connection will become Registered Data, or which for
the purposes of the Plant and/or Apparatus concerned as at the date of
submission are Registered Data, but in each case which for the seven
succeeding Financial Years will be an estimate of what is expected.
EU Transparency
Availability Data
Such data as Customers and Generators are required to provide under
Articles 7.1(a) and 7.1(b) and Articles 15.1(a), 15.1(b), 15.1(c), 15.1(d) of
European Commission Regulation (EU) No. 543/2013 respectively
(known as the Transparency Regulation), and which also forms part of
DRC Schedule 6 (Users’ Outage Data).
European Specification
A common technical specification, a British Standard implementing a
European standard or a European technical approval. The terms
"common technical specification", "European standard" and "European
technical approval" shall have the meanings respectively ascribed to
them in the Regulations.
Event
An unscheduled or unplanned (although it may be anticipated)
occurrence on, or relating to, a System (including Embedded Power
Stations) including, without limiting that general description, faults,
incidents and breakdowns and adverse weather conditions being
experienced.
Exciter
The source of the electrical power providing the field current of a
synchronous machine.
Excitation System
The equipment providing the field current of a machine, including all
regulating and control elements, as well as field discharge or suppression
equipment and protective devices.
Excitation System NoLoad Negative Ceiling
Voltage
The minimum value of direct voltage that the Excitation System is able
to provide from its terminals when it is not loaded, which may be zero or
a negative value.
Excitation System
Nominal Response
Shall have the meaning ascribed to that term in IEC 34-16-1:1991
[equivalent to British Standard BS4999 Section 116.1 : 1992]. The time
interval applicable is the first half-second of excitation system voltage
response.
Excitation System OnLoad Positive Ceiling
Voltage
Shall have the meaning ascribed to the term 'Excitation system on load
ceiling voltage' in IEC 34-16-1:1991[equivalent to British Standard
BS4999 Section 116.1 : 1992].
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Excitation System NoLoad Positive Ceiling
Voltage
Shall have the meaning ascribed to the term 'Excitation system no load
ceiling voltage' in IEC 34-16-1:1991[equivalent to British Standard
BS4999 Section 116.1 : 1992].
Exemptable
Has the meaning set out in the CUSC.
Existing AGR Plant
The following nuclear advanced gas cooled reactor plant (which was
commissioned and connected to the Total System at the Transfer
Date):(a)
Dungeness B
(b)
Hinkley Point B
(c)
Heysham 1
(d)
Heysham 2
(e)
Hartlepool
(f)
Hunterston B
(g)
Torness
Existing AGR Plant
Flexibility Limit
In respect of each Genset within each Existing AGR Plant which has a
safety case enabling it to so operate, 8 (or such lower number which
when added to the number of instances of reduction of output as
instructed by NGET in relation to operation in Frequency Sensitive
Mode totals 8) instances of flexibility in any calendar year (or such lower
or greater number as may be agreed by the Nuclear Installations
Inspectorate and notified to NGET) for the purpose of assisting in the
period of low System NRAPM and/or low Localised NRAPM provided
that in relation to each Generating Unit each change in output shall not
be required to be to a level where the output of the reactor is less than
80% of the reactor thermal power limit (as notified to NGET and which
corresponds to the limit of reactor thermal power as contained in the
"Operating Rules" or "Identified Operating Instructions" forming part of
the safety case agreed with the Nuclear Installations Inspectorate).
Existing Gas Cooled
Reactor Plant
Both Existing Magnox Reactor Plant and Existing AGR Plant.
Existing Magnox
Reactor Plant
The following nuclear gas cooled reactor plant (which was commissioned
and connected to the Total System at the Transfer Date):-
Export and Import
Limits
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(a)
Calder Hall
(b)
Chapelcross
(c)
Dungeness A
(d)
Hinkley Point A
(e)
Oldbury-on-Severn
(f)
Bradwell
(g)
Sizewell A
(h)
Wylfa
Those parameters listed in Appendix 1 to BC1 under the heading BM
Unit Data – Export and Import Limits.
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External
Interconnection
Apparatus for the transmission of electricity to or from the National
Electricity Transmission System or a User System into or out of an
External System. For the avoidance of doubt, a single External
Interconnection may comprise several circuits operating in parallel.
External
Interconnection Circuit
Plant or Apparatus which comprises a circuit and which operates in
parallel with another circuit and which forms part of the External
Interconnection.
Externally
Interconnected System
Operator or EISO
A person who operates an External System which is connected to the
National Electricity Transmission System or a User System by an
External Interconnection.
External System
In relation to an Externally Interconnected System Operator means
the transmission or distribution system which it owns or operates which is
located outside the National Electricity Transmission System
Operator Area any Apparatus or Plant which connects that system to
the External Interconnection and which is owned or operated by such
Externally Interconnected System Operator.
Fault Current
Interruption Time
The time interval from fault inception until the end of the break time of the
circuit breaker (as declared by the manufacturers).
Fast Start
A start by a Genset with a Fast Start Capability.
Fast Start Capability
The ability of a Genset to be Synchronised and Loaded up to full Load
within 5 minutes.
Fast Track Criteria
A proposed Grid Code Modification Proposal that, if implemented,
(a) would meet the Self-Governance Criteria; and
(b) is properly a housekeeping modification required
as a result of some error or factual change,
including but not limited to:
(i) updating names or addresses listed in the Grid Code;
(ii) correcting any minor typographical errors;
(iii) correcting formatting and consistency errors, such as paragraph
numbering; or
(iv) updating out of date references to other documents or paragraphs
Final Generation Outage
Programme
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An outage programme as agreed by NGET with each Generator and
each Interconnector Owner at various stages through the Operational
Planning Phase and Programming Phase which does not commit the
parties to abide by it, but which at various stages will be used as the
basis on which National Electricity Transmission System outages will
be planned.
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Final Operational
Notification or FON
A notification from NGET to a Generator or DC Converter Station
owner confirming that the User has demonstrated compliance:
(a)
with the Grid Code, (or where they apply, that relevant derogations
have been granted), and
(b)
where applicable, with Appendices F1 to F5 of the Bilateral
Agreement,
in each case in respect of the Plant and Apparatus specified in such
notification.
Final Physical
Notification Data
Has the meaning set out in the BSC.
Final Report
A report prepared by the Test Proposer at the conclusion of a System
Test for submission to NGET (if it did not propose the System Test) and
other members of the Test Panel.
Financial Year
Bears the meaning given in Condition A1 (Definitions and Interpretation)
of NGET’s Transmission Licence.
Fixed Proposed
Implementation Date
The proposed date(s) for the implementation of a Grid Code
Modification Proposal or Workgroup Alternative Grid Code
Modification such date to be a specific date by reference to an assumed
date by which a direction from the Authority approving the Grid Code
Modification Proposal or Workgroup Alternative Grid Code
Modification is required in order for the Grid Code Modification
Proposal or any Workgroup Alternative Grid Code Modification, if it
were approved, to be implemented by the proposed date.
Flicker Severity
A value derived from 12 successive measurements of Flicker Severity
(Short Term) (over a two hour period) and a calculation of the cube root
of the mean sum of the cubes of 12 individual measurements, as further
set out in Engineering Recommendation P28 as current at the
Transfer Date.
(Long Term)
Flicker Severity
(Short Term)
A measure of the visual severity of flicker derived from the time series
output of a flickermeter over a 10 minute period and as such provides an
indication of the risk of Customer complaints.
Forecast Data
Those items of Standard Planning Data and Detailed Planning Data
which will always be forecast.
Frequency
The number of alternating current cycles per second (expressed in Hertz)
at which a System is running.
Frequency Sensitive
AGR Unit
Each Generating Unit in an Existing AGR Plant for which the
Generator has notified NGET that it has a safety case agreed with the
Nuclear Installations Inspectorate enabling it to operate in Frequency
Sensitive Mode, to the extent that such unit is within its Frequency
Sensitive AGR Unit Limit. Each such Generating Unit shall be treated
as if it were operating in accordance with BC3.5.1 provided that it is
complying with its Frequency Sensitive AGR Unit Limit.
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Frequency Sensitive
AGR Unit Limit
In respect of each Frequency Sensitive AGR Unit, 8 (or such lower
number which when added to the number of instances of flexibility for the
purposes of assisting in a period of low System or Localised NRAPM
totals 8) instances of reduction of output in any calendar year as
instructed by NGET in relation to operation in Frequency Sensitive
Mode (or such greater number as may be agreed between NGET and
the Generator), for the purpose of assisting with Frequency control,
provided the level of operation of each Frequency Sensitive AGR Unit
in Frequency Sensitive Mode shall not be outside that agreed by the
Nuclear Installations Inspectorate in the relevant safety case.
Frequency Sensitive
Mode
A Genset operating mode which will result in Active Power output
changing, in response to a change in System Frequency, in a direction
which assists in the recovery to Target Frequency, by operating so as to
provide Primary Response and/or Secondary Response and/or High
Frequency Response.
Fuel Security Code
The document of that title designated as such by the Secretary of State,
as from time to time amended.
Gas Turbine Unit
A Generating Unit driven by a gas turbine (for instance by an aeroengine).
Gas Zone Diagram
A single line diagram showing boundaries of, and interfaces between,
gas-insulated HV Apparatus modules which comprise part, or the whole,
of a substation at a Connection Site (or in the case of OTSDUW Plant
and Apparatus, Transmission Interface Site), together with the
associated stop valves and gas monitors required for the safe operation
of the National Electricity Transmission System or the User System,
as the case may be.
Gate Closure
Has the meaning set out in the BSC.
GCDF
Means the Grid Code Development Forum.
General Conditions or
GC
That portion of the Grid Code which is identified as the General
Conditions.
Generating Plant
Demand Margin
The difference between Output Usable and forecast Demand.
Generating Unit
An Onshore Generating Unit and/or an Offshore Generating Unit.
Generating Unit Data
The Physical Notification, Export and Import Limits and Other
Relevant Data only in respect of each Generating Unit:
Generation Capacity
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(a)
which forms part of the BM Unit which represents that Cascade
Hydro Scheme;
(b)
at an Embedded Exemptable Large Power Station, where the
relevant Bilateral Agreement specifies that compliance with BC1
and/or BC2 is required:
(i)
to each Generating Unit, or
(ii)
to each Power Park Module where the Power Station
comprises Power Park Modules
Has the meaning set out in the BSC.
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Generation Planning
Parameters
Those parameters listed in Appendix 2 of OC2.
Generator
A person who generates electricity under licence or exemption under the
Act acting in its capacity as a generator in Great Britain or Offshore.
Generator Performance
Chart
A diagram which shows the MW and Mvar capability limits within which a
Generating Unit will be expected to operate under steady state
conditions.
Genset
A Generating Unit, Power Park Module or CCGT Module at a Large
Power Station or any Generating Unit, Power Park Module or CCGT
Module which is directly connected to the National Electricity
Transmission System.
Good Industry Practice
The exercise of 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.
Governance Rules or
GR
That portion of the Grid Code which is identified as the Governance
Rules.
Governor Deadband
The total magnitude of the change in steady state speed (expressed as a
range of Hz (± x Hz) where "x" is a numerical value) within which there is
no resultant change in the position of the governing valves of the
speed/load Governing System.
Great Britain or GB
The landmass of England and Wales and Scotland, including internal
waters.
Grid Code Fast Track
Proposals
A proposal to modify the Grid Code which is raised pursuant to GR.26
and has not yet been approved or rejected by the Grid Code Review
Panel.
Grid Code Modification
Fast Track Report
A report prepared pursuant to GR.26
Grid Code Modification
Register
Has the meaning given in GR.13.1.
Grid Code Modification
Report
Has the meaning given in GR.22.1.
Grid Code Modification
Procedures
The procedures for the modification of the Grid Code (including the
implementation of Approved Modifications) as set out in the
Governance Rules.
Grid Code Modification
Proposal
A proposal to modify the Grid Code which is not yet rejected pursuant to
GR.15.5 or GR.15.6 and has not yet been implemented.
Grid Code Modification
Self- Governance
Report
Has the meaning given in GR.24.5
Grid Code Objectives
Means the objectives referred to in Paragraph 1b of Standard Condition
C14 of NGET’s Transmission Licence.
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Grid Code Review Panel
or Panel
The panel with the functions set out in GR.1.2.
Grid Code Review Panel The vote of Panel Members undertaken by the Panel Chairman in
accordance with Paragraph GR.22.4 as to whether in their view they
Recommendation Vote
believe each proposed Grid Code Modification Proposal, or
Workgroup Alternative Grid Code Modification would better facilitate
achievement of the Grid Code Objective(s) and so should be made.
Grid Code Review Panel
Self-Governance Vote
The vote of Panel Members undertaken by the Panel Chairman in
accordance with GR.24.9 as to whether they believe each proposed Grid
Code Modification Proposal, as compared with the then existing
provisions of the Grid Code and any Workgroup Alternative Grid Code
Modification set out in the Grid Code Modification Self- Governance
Report, would better facilitate achievement of the Grid Code
Objective(s).
Grid Code SelfGovernance Proposals
Grid Code Modification Proposals which satisfy the Self Governance
Criteria.
Grid Entry Point
An Onshore Grid Entry Point or an Offshore Grid Entry Point.
Grid Supply Point
A point of supply from the National Electricity Transmission System to
Network Operators or Non-Embedded Customers.
Group
Those National Electricity Transmission System sub-stations bounded
solely by the faulted circuit(s) and the overloaded circuit(s) excluding any
third party connections between the Group and the rest of the National
Electricity Transmission System, the faulted circuit(s) being a Secured
Event.
Headroom
The Power Available (in MW) less the actual Active Power exported
from the Power Park Module (in MW).
High Frequency
Response
An automatic reduction in Active Power output in response to an
increase in System Frequency above the Target Frequency (or such
other level of Frequency as may have been agreed in an Ancillary
Services Agreement). This reduction in Active Power output must be in
accordance with the provisions of the relevant Ancillary Services
Agreement which will provide that it will be released increasingly with
time over the period 0 to 10 seconds from the time of the Frequency
increase on the basis set out in the Ancillary Services Agreement and
fully achieved within 10 seconds of the time of the start of the Frequency
increase and it must be sustained at no lesser reduction thereafter. The
interpretation of the High Frequency Response to a + 0.5 Hz frequency
change is shown diagrammatically in Figure CC.A.3.3.
High Voltage or HV
For E&W Transmission Systems, a voltage exceeding 650 volts. For
Scottish Transmission Systems, a voltage exceeding 1000 volts.
HV Connections
Apparatus connected at the same voltage as that of the National
Electricity Transmission System, including Users' circuits, the higher
voltage windings of Users' transformers and associated connection
Apparatus.
HP Turbine Power
Fraction
Ratio of steady state mechanical power delivered by the HP turbine to
the total steady state mechanical power delivered by the total steam
turbine at Registered Capacity.
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IEC
International Electrotechnical Commission.
IEC Standard
A standard approved by the International Electrotechnical Commission.
Implementation Date
Is the date and time for implementation of an Approved Modification as
specified in accordance with Paragraph GR.25.3.
Implementing Safety
Co-ordinator
The Safety Co-ordinator implementing Safety Precautions.
Import Usable
That portion of Registered Import Capacity which is expected to be
available and which is not unavailable due to a Planned Outage.
Incident Centre
A centre established by NGET or a User as the focal point in NGET or in
that User, as the case may be, for the communication and dissemination
of information between the senior management representatives of NGET,
or of that User, as the case may be, and the relevant other parties during
a Joint System Incident in order to avoid overloading NGET's, or that
User's, as the case may be, existing operational/control arrangements.
Independent Back-Up
Protection
A Back-Up Protection system which utilises a discrete relay, different
current transformers and an alternate operating principle to the Main
Protection systems(s) such that it can operate autonomously in the
event of a failure of the Main Protection.
Independent Main
Protection
A Main Protection system which utilises a physically discrete relay and
different current transformers to any other Main Protection.
Indicated Constraint
Boundary Margin
The difference between a constraint boundary transfer limit and the
difference between the sum of BM Unit Maximum Export Limits and the
forecast of local Demand within the constraint boundary.
Indicated Imbalance
The difference between the sum of Physical Notifications for BM Units
comprising Generating Units or CCGT Modules and the forecast of
Demand for the whole or any part of the System.
Indicated Margin
The difference between the sum of BM Unit Maximum Export Limits
submitted and the forecast of Demand for the whole or any part of the
System
Instructor Facilities
A device or system which gives certain Transmission Control Centre
instructions with an audible or visible alarm, and incorporates the means
to return message acknowledgements to the Transmission Control
Centre
Integral Equipment Test
or IET
A test on equipment, associated with Plant and/or Apparatus, which
takes place when that Plant and/or Apparatus forms part of a
Synchronised System and which, in the reasonable judgement of the
person wishing to perform the test, may cause an Operational Effect.
Intellectual Property" or
"IPRs
Patents, trade marks, service marks, rights in designs, trade names,
copyrights and topography rights (whether or not any of the same are
registered and including applications for registration of any of the same)
and rights under licences and consents in relation to any of the same and
all rights or forms of protection of a similar nature or having equivalent or
similar effect to any of the same which may subsist anywhere in the
world.
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Interconnection
Agreement
An agreement made between NGET and an Externally Interconnected
System Operator and/or an Interconnector User and/or other relevant
persons for the External Interconnection relating to an External
Interconnection and/or an agreement under which an Interconnector
User can use an External Interconnection.
Interconnector Export
Capacity
In relation to an External Interconnection means the (daily or weekly)
forecast value (in MW) at the time of the (daily or weekly) peak demand,
of the maximum level at which the External Interconnection can export
to the Grid Entry Point.
Interconnector Import
Capacity
In relation to an External Interconnection means the (daily or weekly)
forecast value (in MW) at the time of the (daily or weekly) peak demand
of the maximum level at which the External Interconnection can import
from the Grid Entry Point.
Interconnector Owner
Has the meaning given to the term in the Connection and Use of
System Code.
Interconnector User
Has the meaning set out in the BSC.
Interface Agreement
Has the meaning set out in the CUSC.
Interface Point
As the context admits or requires either;
(a)
the electrical point of connection between an Offshore
Transmission System and an Onshore Transmission System,
or
(b)
the electrical point of connection between an Offshore
Transmission System and a Network Operator’s User System.
Interface Point Capacity
The maximum amount of Active Power transferable at the Interface
Point as declared by a User under the OTSDUW Arrangements
expressed in whole MW.
Interface Point Target
Voltage/Power factor
The nominal target voltage/power factor at an Interface Point which a
Network Operator requires NGET to achieve by operation of the
relevant Offshore Transmission System.
Interim Operational
Notification or ION
A notification from NGET to a Generator or DC Converter Station
owner acknowledging that the User has demonstrated compliance,
except for the Unresolved Issues;
(a)
with the Grid Code, and
(b)
where applicable, with Appendices F1 to F5 of the Bilateral
Agreement,
in each case in respect of the Plant and Apparatus (including OTSUA)
specified in such notification and provided that in the case of the
OTSDUW Arrangements such notification shall be provided to a
Generator in two parts dealing with the OTSUA and Generator’s Plant
and Apparatus (called respectively “Interim Operational Notification
Part A” or “ION A” and “Interim Operational Notification Part B” or
“ION B”) as provided for in the CP.
Intermittent Power
Source
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The primary source of power for a Generating Unit that can not be
considered as controllable, e.g. wind, wave or solar.
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Intertripping
(a)
The tripping of circuit-breaker(s) by commands initiated from
Protection at a remote location independent of the state of the
local Protection; or
(b)
Operational Intertripping.
Intertrip Apparatus
Apparatus which performs Intertripping.
IP Turbine Power
Fraction
Ratio of steady state mechanical power delivered by the IP turbine to the
total steady state mechanical power delivered by the total steam turbine
at Registered Capacity.
Isolating Device
A device for achieving Isolation.
Isolation
The disconnection of HV Apparatus (as defined in OC8A.1.6.2 and
OC8B.1.7.2) from the remainder of the System in which that HV
Apparatus is situated by either of the following:
(a)
(b)
an Isolating Device maintained in an isolating position. The
isolating position must either be:
(i)
maintained by immobilising and Locking the Isolating
Device in the isolating position and affixing a Caution
Notice to it. Where the Isolating Device is Locked with a
Safety Key, the Safety Key must be secured in a Key Safe
and the Key Safe Key must be, where reasonably
practicable, given to the authorised site representative of the
Requesting Safety Co-Ordinator and is to be retained in
safe custody. Where not reasonably practicable the Key
Safe Key must be retained by the authorised site
representative of the Implementing Safety Co-ordinator in
safe custody; or
(ii)
maintained and/or secured by such other method which
must be in accordance with the Local Safety Instructions
of NGET or the Safety Rules of the Relevant
Transmission Licensee or that User, as the case may be;
or
an adequate physical separation which must be in accordance with
and maintained by the method set out in the Local Safety
Instructions of NGET or the Safety Rules of the Relevant
Transmission Licensee or that User, as the case may be.
Joint BM Unit Data
Has the meaning set out in the BSC.
Joint System Incident
An Event wherever occurring (other than on an Embedded Medium
Power Station or an Embedded Small Power Station) which, in the
opinion of NGET or a User, has or may have a serious and/or
widespread effect, in the case of an Event on a User(s) System(s)
(other than on an Embedded Medium Power Station or Embedded
Small Power Station), on the National Electricity Transmission
System, and in the case of an Event on the National Electricity
Transmission System, on a User(s) System(s) (other than on an
Embedded Medium Power Station or Embedded Small Power
Station).
Key Safe
A device for the secure retention of keys.
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Key Safe Key
A key unique at a Location capable of operating a lock, other than a
control lock, on a Key Safe.
Large Power Station
A Power Station which is
(a)
directly connected to:
(i)
NGET’s Transmission System where such Power Station
has a Registered Capacity of 100MW or more; or
(ii)
SPT’s Transmission System where such Power Station
has a Registered Capacity of 30MW or more; or
(iii)
SHETL’s Transmission System where such Power
Station has a Registered Capacity of 10MW or more; or
(iv)
an Offshore Transmission System where such Power
Station has a Registered Capacity of 10MW or more;
or,
(b)
Embedded within a User System (or part thereof) where such
User System (or part thereof) is connected under normal
operating conditions to:
(i)
NGET’s Transmission System and such Power Station
has a Registered Capacity of 100MW or more; or
(ii)
SPT’s Transmission System and such Power Station has
a Registered Capacity of 30MW or more; or
(iii)
SHETL’s Transmission System and such Power Station
has a Registered Capacity of 10MW or more;
or,
(c)
Embedded within a User System (or part thereof) where the User
System (or part thereof) is not connected to the National
Electricity Transmission System, although such Power Station
is in:
(i)
NGET’s Transmission Area where such Power Station
has a Registered Capacity of 100MW or more; or
(ii)
SPT’s Transmission Area where such Power Station has
a Registered Capacity of 30MW or more; or
(iii)
SHETL’s Transmission Area where such Power Station
has a Registered Capacity of 10MW or more;
Legal Challenge
Where permitted by lawa judicial review in respect of the Authority’s
decision to approve or not to approve a Grid Code Modification
Proposal.
Licence
Any licence granted to NGET or a Relevant Transmission Licensee or
a User, under Section 6 of the Act.
Licence Standards
Those standards set out or referred to in Condition C17 of NGET’s
Transmission Licence and/or Condition D3 and/or Condition E16 of a
Relevant Transmission Licensee’s Transmission Licence .
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Limited Frequency
Sensitive Mode
A mode whereby the operation of the Genset (or DC Converter at a DC
Converter Station exporting Active Power to the Total System) is
Frequency insensitive except when the System Frequency exceeds
50.4Hz, from which point Limited High Frequency Response must be
provided.
Limited High Frequency
Response
A response of a Genset (or DC Converter at a DC Converter Station
exporting Active Power to the Total System) to an increase in System
Frequency above 50.4Hz leading to a reduction in Active Power in
accordance with the provisions of BC3.7.2.
Limited Operational
Notification or LON
A notification from NGET to a Generator or DC Converter Station
owner stating that the User’s Plant and/or Apparatus specified in such
notification may be, or is, unable to comply:
(a)
with the provisions of the Grid Code specified in the notice, and
(b)
where applicable, with Appendices F1 to F5 of the Bilateral
Agreement ,
and specifying the Unresolved Issues.
Load
The Active, Reactive or Apparent Power, as the context requires,
generated, transmitted or distributed.
Loaded
Supplying electrical power to the System.
Load Factor
The ratio of the actual output of a Generating Unit to the possible
maximum output of that Generating Unit.
Load Management
Block
A block of Demand controlled by a Supplier or other party through the
means of radio teleswitching or by some other means.
Local Joint Restoration
Plan
A plan produced under OC9.4.7.12 detailing the agreed method and
procedure by which a Genset at a Black Start Station (possibly with
other Gensets at that Black Start Station) will energise part of the Total
System and meet complementary blocks of local Demand so as to form
a Power Island.
In Scotland, the plan may also: cover more than one Black Start
Station; include Gensets other than those at a Black Start Station and
cover the creation of one or more Power Islands.
Local Safety
Instructions
For safety co-ordination in England and Wales, instructions on each User
Site and Transmission Site, approved by the relevant NGET or User's
manager, setting down the methods of achieving the objectives of
NGET's or the User's Safety Rules, as the case may be, to ensure the
safety of personnel carrying out work or testing on Plant and/or
Apparatus on which his Safety Rules apply and, in the case of a User,
any other document(s) on a User Site which contains rules with regard to
maintaining or securing the isolating position of an Isolating Device, or
maintaining a physical separation or maintaining or securing the position
of an Earthing Device.
Local Switching
Procedure
A procedure produced under OC7.6 detailing the agreed arrangements in
respect of carrying out of Operational Switching at Connection Sites
and parts of the National Electricity Transmission System adjacent to
those Connection Sites.
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Localised Negative
Reserve Active Power
Margin or Localised
NRAPM
That margin of Active Power sufficient to allow transfers to and from a
System Constraint Group (as the case may be) to be contained within
such reasonable limit as NGET may determine.
Location
Any place at which Safety Precautions are to be applied.
Locked
A condition of HV Apparatus that cannot be altered without the operation
of a locking device.
Locking
The application of a locking device which enables HV Apparatus to be
Locked.
Low Frequency Relay
Has the same meaning as Under Frequency Relay.
Low Voltage or LV
For E&W Transmission Systems a voltage not exceeding 250 volts. For
Scottish Transmission Systems, a voltage exceeding 50 volts but not
exceeding 1000 volts.
LV Side of the Offshore
Platform
Unless otherwise specified in the Bilateral Agreement, the busbar on
the Offshore Platform (typically 33kV) at which the relevant Offshore
Grid Entry Point is located.
Main Protection
A Protection system which has priority above other Protection in
initiating either a fault clearance or an action to terminate an abnormal
condition in a power system.
Manufacturer’s Data &
Performance Report
A report submitted by a manufacturer to NGET relating to a specific
version of a Power Park Unit demonstrating the performance
characteristics of such Power Park Unit in respect of which NGET has
evaluated its relevance for the purposes of the Compliance Processes.
Market Operation Data
Interface System
(MODIS)
A computer system operated by NGET and made available for use by
Customers connected to or using the National Electricity
Transmission System for the purpose of submitting EU Transparency
Availability Data to NGET.
Market Suspension
Threshold
Has the meaning given to the term ‘Market Suspension Threshold’ in
Section G of the BSC.
Material Effect
An effect causing NGET or a Relevant Transmission Licensee to effect
any works or to alter the manner of operation of Transmission Plant
and/or Transmission Apparatus at the Connection Site (which term
shall, in this definition and in the definition of “Modification” only, have
the meaning ascribed thereto in the CUSC) or the site of connection or a
User to effect any works or to alter the manner of operation of its Plant
and/or Apparatus at the Connection Site or the site of connection which
in either case involves that party in expenditure of more than £10,000.
Materially Affected Party Any person or class of persons designated by the Authority as such.
Maximum Export
Capacity
The maximum continuous Apparent Power expressed in MVA and
maximum continuous Active Power expressed in MW which can flow
from an Offshore Transmission System connected to a Network
Operator's User System, to that User System.
Maximum Generation
Service or MGS
A service utilised by NGET in accordance with the CUSC and the
Balancing Principles Statement in operating the Total System.
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Maximum Generation
Service Agreement
An agreement between a User and NGET for the payment by NGET to
that User in respect of the provision by such User of a Maximum
Generation Service.
Maximum Import
Capacity
The maximum continuous Apparent Power expressed in MVA and
maximum continuous Active Power expressed in MW which can flow to
an Offshore Transmission System connected to a Network
Operator's User System, from that User System.
Medium Power Station
A Power Station which is
(a)
directly connected to NGET’s Transmission System where such
Power Station has a Registered Capacity of 50MW or more but
less than 100MW;
or,
(b)
Embedded within a User System (or part thereof) where such
User System (or part thereof) is connected under normal
operating conditions to NGET’s Transmission System and such
Power Station has a Registered Capacity of 50MW or more but
less than 100MW;
or,
(c)
Embedded within a User System (or part thereof) where the User
System (or part thereof) is not connected to the National
Electricity Transmission System, although such Power Station
is in NGET’s Transmission Area and such Power Station has a
Registered Capacity of 50MW or more but less than 100MW.
Medium Voltage or MV
For E&W Transmission Systems a voltage exceeding 250 volts but not
exceeding 650 volts.
Mills
Milling plant which supplies pulverised fuel to the boiler of a coal fired
Power Station.
Minimum Generation
The minimum output (in whole MW) which a Genset can generate or DC
Converter at a DC Converter Station can import or export to the Total
System under stable operating conditions, as registered with NGET
under the PC (and amended pursuant to the PC). For the avoidance of
doubt, the output may go below this level as a result of operation in
accordance with BC3.7.
Minimum Import
Capacity
The minimum input (in whole MW) into a DC Converter at a DC
Converter Station (in any of its operating configurations) at the Onshore
Grid Entry Point (or in the case of an Embedded DC Converter at the
User System Entry Point) at which a DC Converter can operate in a
stable manner, as registered with NGET under the PC (and amended
pursuant to the PC).
Modification
Any actual or proposed replacement, renovation, modification, alteration
or construction by or on behalf of a User or NGET to either that User’s
Plant or Apparatus or Transmission Plant or Apparatus, as the case
may be, or the manner of its operation which has or may have a Material
Effect on NGET or a User, as the case may be, at a particular
Connection Site.
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Mothballed DC
Converter at a DC
Converter Station
A DC Converter at a DC Converter Station that has previously imported
or exported power which the DC Converter Station owner plans not to
use to import or export power for the remainder of the current Financial
Year but which could be returned to service.
Mothballed Generating
Unit
A Generating Unit that has previously generated which the Generator
plans not to use to generate for the remainder of the current NGET
Financial Year but which could be returned to service.
Mothballed Power Park
Module
A Power Park Module that has previously generated which the
Generator plans not to use to generate for the remainder of the current
Financial Year but which could be returned to service.
Multiple Point of
Connection
A double (or more) Point of Connection, being two (or more) Points of
Connection interconnected to each other through the User’s System.
National Demand
The amount of electricity supplied from the Grid Supply Points plus:
that supplied by Embedded Large Power Stations, and

National Electricity Transmission System Losses,
minus:
the Demand taken by Station Transformers and Pumped
Storage Units’
and, for the purposes of this definition, does not include:
any exports from the National Electricity Transmission System
across External Interconnections.
National Electricity
Transmission System
The Onshore Transmission System and, where owned by Offshore
Transmission Licensees, Offshore Transmission Systems.
National Electricity
Transmission System
Demand
The amount of electricity supplied from the Grid Supply Points plus:
that supplied by Embedded Large Power Stations, and

exports from the National Electricity Transmission System
across External Interconnections, and

National Electricity Transmission System Losses,
and, for the purposes of this definition, includes:
the Demand taken by Station Transformers and Pumped
Storage Units.
National Electricity
Transmission System
Losses
The losses of electricity incurred on the National Electricity
Transmission System.
National Electricity
Transmission System
Operator Area
Has the meaning set out in Schedule 1 of NGET's Transmission
Licence.
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National Electricity
Transmission System
Study Network Data File
A computer file produced by NGET which in NGET’s view provides an
appropriate representation of the National Electricity Transmission
System for a specific point in time. The computer file will contain
information and data on Demand on the National Electricity
Transmission System and on Large Power Stations including Genset
power output consistent with Output Usable and NGET’s view of
prevailing system conditions.
National Electricity
Transmission System
Warning
A warning issued by NGET to Users (or to certain Users only) in
accordance with OC7.4.8.2, which provides information relating to
System conditions or Events and is intended to :
(a)
alert Users to possible or actual Plant shortage, System problems
and/or Demand reductions;
(b)
inform of the applicable period;
(c)
indicate intended consequences for Users; and
(d)
enable specified Users to be in a state of readiness to receive
instructions from NGET.
National Electricity
Transmission System
Warning - Demand
Control Imminent
A warning issued by NGET, in accordance with OC7.4.8.7, which is
intended to provide short term notice, where possible, to those Users
who are likely to receive Demand reduction instructions from NGET
within 30 minutes.
National Electricity
Transmission System
Warning - High Risk of
Demand Reduction
A warning issued by NGET, in accordance with OC7.4.8.6, which is
intended to alert recipients that there is a high risk of Demand reduction
being implemented and which may normally result from an Electricity
Margin Notice.
National Electricity
Transmission System
Warning - Electricity
Margin Notice
A warning issued by NGET, in accordance with OC7.4.8.5, which is
intended to invite a response from and to alert recipients to a decreased
System Margin.
National Electricity
Transmission System
Warning - Risk of
System Disturbance
A warning issued by NGET, in accordance with OC7.4.8.8, which is
intended to alert Users of the risk of widespread and serious System
disturbance which may affect Users.
Network Data
The data to be provided by NGET to Users in accordance with the PC,
as listed in Part 3 of the Appendix to the PC.
Network Operator
A person with a User System directly connected to the National
Electricity Transmission System to which Customers and/or Power
Stations (not forming part of the User System) are connected, acting in
its capacity as an operator of the User System, but shall not include a
person acting in the capacity of an Externally Interconnected System
Operator or a Generator in respect of OTSUA.
NGET
National Grid Electricity Transmission plc (NO: 2366977) whose
registered office is at 1-3 Strand, London, WC2N 5EH.
NGET Control Engineer
The nominated person employed by NGET to direct the operation of the
National Electricity Transmission System or such person as
nominated by NGET.
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NGET Operational
Strategy
NGET's operational procedures which form the guidelines for operation
of the National Electricity Transmission System.
No-Load Field Voltage
Shall have the meaning ascribed to that term in IEC 34-16-1:1991
[equivalent to British Standard BS4999 Section 116.1 : 1992].
No System Connection
As defined in OC8A.1.6.2 and OC8B.1.7.2
Notification of User’s
Intention to
Synchronise
A notification from a Generator or DC Converter Station owner to
NGET informing NGET of the date upon which any OTSUA, a
Generating Unit(s), CCGT Module(s), Power Park Module(s) or DC
Converter(s) will be ready to be Synchronised to the Total System.
Non-Embedded
Customer
A Customer in Great Britain, except for a Network Operator acting in
its capacity as such, receiving electricity direct from the Onshore
Transmission System irrespective of from whom it is supplied.
Non-Synchronous
Generating Unit
An Onshore Non-Synchronous Generating Unit or Offshore NonSynchronous Generating Unit.
Normal CCGT Module
A CCGT Module other than a Range CCGT Module.
Novel Unit
A tidal, wave, wind, geothermal, or any similar, Generating Unit.
OC9 De-synchronised
Island Procedure
Has the meaning set out in OC9.5.4.
Offshore
Means wholly or partly in Offshore Waters, and when used in
conjunction with another term and not defined means that the associated
term is to be read accordingly.
Offshore DC Converter
Any User Apparatus located Offshore used to convert alternating
current electricity to direct current electricity, or vice versa. An Offshore
DC Converter is a standalone operative configuration at a single site
comprising one or more converter bridges, together with one or more
converter transformers, converter control equipment, essential protective
and switching devices and auxiliaries, if any, used for conversion.
Offshore Development
Information Statement
A statement prepared by NGET in accordance with Special Condition C4
of NGET’s Transmission Licence.
Offshore Generating
Unit
Unless otherwise provided in the Grid Code, any Apparatus located
Offshore which produces electricity, including, an Offshore
Synchronous Generating Unit and Offshore Non-Synchronous
Generating Unit.
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Offshore Grid Entry
Point
In the case of:(a)
an Offshore Generating Unit or an Offshore DC Converter, as
the case may be, which is directly connected to an Offshore
Transmission System, the point at which it connects to that
Offshore Transmission System, or;
(b)
an Offshore Power Park Module which is directly connected to
an Offshore Transmission System, the point where one Power
Park String (registered by itself as a Power Park Module) or the
collection of points where a number of Offshore Power Park
Strings (registered as a single Power Park Module) connects to
that Offshore Transmission System, or;
(c)
an External Interconnection which is directly connected to an
Offshore Transmission System, the point at which it connects to
that Offshore Transmission System.
Offshore NonSynchronous
Generating Unit
An Offshore Generating Unit that is not an Offshore Synchronous
Generating Unit including for the avoidance of doubt a Power Park Unit
located Offshore.
Offshore Platform
A single structure comprising of Plant and Apparatus located Offshore
which includes one or more Offshore Grid Entry Points.
Offshore Power Park
Module
A collection of one or more Offshore Power Park Strings (registered as
a Power Park Module under the PC). There is no limit to the number of
Power Park Strings within the Power Park Module, so long as they
either:
(a)
connect to the same busbar which cannot be electrically split; or
(b)
connect to a collection of directly electrically connected busbars of
the same nominal voltage and are configured in accordance with
the operating arrangements set out in the relevant Bilateral
Agreement.
Offshore Power Park
String
A collection of Offshore Generating Units that are powered by an
Intermittent Power Source, joined together by cables forming part of a
User System with a single point of connection to an Offshore
Transmission System. The connection to an Offshore Transmission
System may include a DC Converter.
Offshore Synchronous
Generating Unit
An Offshore Generating Unit in which, under all steady state conditions,
the rotor rotates at a mechanical speed equal to the electrical frequency
of the National Electricity Transmission System divided by the number
of pole pairs of the Generating Unit.
Offshore Tender
Process
The process followed by the Authority to make, in prescribed cases, a
determination on a competitive basis of the person to whom an offshore
transmission licence is to be granted.
Offshore Transmission
Distribution Connection
Agreement
An agreement entered into by NGET and a Network Operator in respect
of the connection to and use of a Network Operator’s User System by
an Offshore Transmission System.
Offshore Transmission
Licensee
Such person in relation to whose Transmission Licence the standard
conditions in Section E (offshore transmission owner standard conditions)
of such Transmission Licence have been given effect, or any person in
that prospective role who has acceded to the STC.
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Offshore Transmission
System
A system consisting (wholly or mainly) of high voltage electric lines and
used for the transmission of electricity from one Power Station to a substation or to another Power Station or between sub-stations, and
includes any Plant and Apparatus (including OTSUA) and meters in
connection with the transmission of electricity but does not include any
Remote Transmission Assets. An Offshore Transmission System
extends from the Interface Point, or the Offshore Grid Entry Point(s)
and may include Plant and Apparatus located Onshore and Offshore
and, where the context permits, references to the Offshore
Transmission System includes OTSUA.
Offshore Waters
Has the meaning given to “offshore waters” in Section 90(9) of the
Energy Act 2004.
Offshore Works
Assumptions
In relation to a particular User means those assumptions set out in
Appendix P of the relevant Construction Agreement as amended from
time to time.
Onshore
Means within Great Britain, and when used in conjunction with another
term and not defined means that the associated term is to be read
accordingly.
Onshore DC Converter
Any User Apparatus located Onshore with a Completion Date after 1st
April 2005 used to convert alternating current electricity to direct current
electricity, or vice versa. An Onshore DC Converter is a standalone
operative configuration at a single site comprising one or more converter
bridges, together with one or more converter transformers, converter
control equipment, essential protective and switching devices and
auxiliaries, if any, used for conversion. In a bipolar arrangement, an
Onshore DC Converter represents the bipolar configuration.
Onshore Generating
Unit
Unless otherwise provided in the Grid Code, any Apparatus located
Onshore which produces electricity, including, an Onshore
Synchronous Generating Unit and Onshore Non-Synchronous
Generating Unit.
Onshore Grid Entry
Point
A point at which a Onshore Generating Unit or a CCGT Module or a
CCGT Unit or a Onshore DC Converter or a Onshore Power Park
Module or an External Interconnection, as the case may be, which is
directly connected to the Onshore Transmission System connects to
the Onshore Transmission System.
Onshore NonSynchronous
Generating Unit
A Generating Unit located Onshore that is not a Synchronous
Generating Unit including for the avoidance of doubt a Power Park Unit
located Onshore.
Onshore Power Park
Module
A collection of Non-Sychronous Generating Units (registered as a
Power Park Module under the PC) that are powered by an Intermittent
Power Source, joined together by a System with a single electrical point
of connection directly to the Onshore Transmission System (or User
System if Embedded) with no intermediate Offshore Transmission
System connections. The connection to the Onshore Transmission
System (or User System if Embedded) may include a DC Converter.
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Onshore Synchronous
Generating Unit
An Onshore Generating Unit including, for the avoidance of doubt, a
CCGT Unit in which, under all steady state conditions, the rotor rotates at
a mechanical speed equal to the electrical frequency of the National
Electricity Transmission System divided by the number of pole pairs of
the Generating Unit.
Onshore Transmission
Licensee
NGET, SPT, or SHETL.
Onshore Transmission
System
The system consisting (wholly or mainly) of high voltage electric lines
owned or operated by Onshore Transmission Licensees and used for
the transmission of electricity from one Power Station to a substation or
to another Power Station or between substations or to or from Offshore
Transmission Systems or to or from any External Interconnection,
and includes any Plant and Apparatus and meters owned or operated
by any Onshore Transmission Licensee in connection with the
transmission of electricity but does not include any Remote
Transmission Assets.
On-Site Generator Site
A site which is determined by the BSC Panel to be a Trading Unit under
the BSC by reason of having fulfilled the Class 1 or Class 2 requirements
as such terms are used in the BSC.
Operating Code or OC
That portion of the Grid Code which is identified as the Operating Code.
Operating Margin
Contingency Reserve plus Operating Reserve.
Operating Reserve
The additional output from Large Power Stations or the reduction in
Demand, which must be realisable in real-time operation to respond in
order to contribute to containing and correcting any System Frequency
fall to an acceptable level in the event of a loss of generation or a loss of
import from an External Interconnection or mismatch between
generation and Demand.
Operation
A scheduled or planned action relating to the operation of a System
(including an Embedded Power Station).
Operational Data
Data required under the Operating Codes and/or Balancing Codes.
Operational Day
The period from 0500 hours on one day to 0500 on the following day.
Operation Diagrams
Diagrams which are a schematic representation of the HV Apparatus
and the connections to all external circuits at a Connection Site (and in
the case of OTSDUW, Transmission Interface Site), incorporating its
numbering, nomenclature and labelling.
Operational Effect
Any effect on the operation of the relevant other System which causes
the National Electricity Transmission System or the System of the
other User or Users, as the case may be, to operate (or be at a
materially increased risk of operating) differently to the way in which they
would or may have operated in the absence of that effect.
Operational
Intertripping
The automatic tripping of circuit-breakers to prevent abnormal system
conditions occurring, such as over voltage, overload, System instability,
etc. after the tripping of other circuit-breakers following power System
fault(s) which includes System to Generating Unit, System to CCGT
Module, System to Power Park Module, System to DC Converter and
System to Demand intertripping schemes.
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Operational
Notifications
Any Energisation Operational Notification, Interim Operational
Notification, Final Operational Notification or Limited Operational
Notification issued from NGET to a User.
Operational Planning
Planning through various timescales the matching of generation output
with forecast National Electricity Transmission System Demand
together with a reserve of generation to provide a margin, taking into
account outages of certain Generating Units, of parts of the National
Electricity Transmission System and of parts of User Systems to
which Power Stations and/or Customers are connected, carried out to
achieve, so far as possible, the standards of security set out in NGET’s
Transmission Licence, each Relevant Transmission Licensee’s
Transmission Licence or Electricity Distribution Licence, as the case
may be.
Operational Planning
Margin
An operational planning margin set by NGET.
Operational Planning
Phase
The period from 8 weeks to the end of the 5th year ahead of real time
operation.
Operational Procedures
Management instructions and procedures, both in support of the Safety
Rules and for the local and remote operation of Plant and Apparatus,
issued in connection with the actual operation of Plant and/or Apparatus
at or from a Connection Site.
Operational Switching
Operation of Plant and/or Apparatus to the instruction of the relevant
Control Engineer. For the avoidance of doubt, the operation of
Transmission Plant and/or Apparatus forming part of the National
Electricity Transmission System in England and Wales, will be to the
instruction of NGET and in Scotland and Offshore will be to the
instruction of the Relevant Transmission Licensee.
Other Relevant Data
The data listed in BC1.4.2(f) under the heading Other Relevant Data.
Offshore Transmission
System Development
User Works or OTSDUW
In relation to a particular User where the OTSDUW Arrangements
apply, means those activities and/or works for the design, planning,
consenting and/or construction and installation of the Offshore
Transmission System to be undertaken by the User as identified in Part
2 of Appendix I of the relevant Construction Agreement.
OTSDUW Arrangements The arrangements whereby certain aspects of the design, consenting,
construction, installation and/or commissioning of transmission assets
are capable of being undertaken by a User prior to the transfer of those
assets to a Relevant Transmission Licensee under an Offshore
Tender Process.
OTSDUW Data and
Information
The data and information to be provided by Users undertaking
OTSDUW, to NGET in accordance with Appendix F of the Planning
Code.
OTSDUW DC Converter
A Transmission DC Converter designed and/or constructed and/or
installed by a User under the OTSDUW Arrangements and/or operated
by the User until the OTSUA Transfer Time.
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OTSDUW Development
and Data Timetable
The timetable for both the delivery of OTSDUW Data and Information
and OTSDUW Network Data and Information as referred to in
Appendix F of the Planning Code and the development of the scope of
the OTSDUW.
OTSDUW Network Data
and Information
The data and information to be provided by NGET to Users undertaking
OTSDUW in accordance with Appendix F of the Planning Code.
OTSDUW Plant and
Apparatus
Plant and Apparatus, including any OTSDUW DC Converter, designed
by the User under the OTSDUW Arrangements.
Offshore Transmission
System User Assets or
OTSUA
OTSDUW Plant and Apparatus constructed and/or installed by a User
under the OTSDUW Arrangements which form an Offshore
Transmission System that once transferred to a Relevant
Transmission Licensee under an Offshore Tender Process will
become part of the National Electricity Transmission System.
OTSUA Transfer Time
The time and date at which the OTSUA are transferred to a Relevant
Transmission Licensee.
Out of Synchronism
The condition where a System or Generating Unit cannot meet the
requirements to enable it to be Synchronised.
Output Usable or OU
The (daily or weekly) forecast value (in MW), at the time of the (daily or
weekly) peak demand, of the maximum level at which the Genset can
export to the Grid Entry Point, or in the case of Embedded Power
Stations, to the User System Entry Point. In addition, for a Genset
powered by an Intermittent Power Source the forecast value is based
upon the Intermittent Power Source being at a level which would
enable the Genset to generate at Registered Capacity.
For the purpose of OC2 only, the term Output Usable shall include the
terms Interconnector Export Capacity and Interconnector Import
Capacity where the term Output Usable is being applied to an External
Interconnection.
Over-excitation Limiter
Shall have the meaning ascribed to that term in IEC 34-16-1:1991
[equivalent to British Standard BS4999 Section 116.1 : 1992].
Panel Chairman
A person appointed as such in accordance with GR.4.1.
Panel Member
Any of the persons identified as such in GR.4.
Panel Members’
Recommendation
The recommendation in accordance with the "Grid Code Review Panel
Recommendation Vote"
Panel Secretary
A person appointed as such in accordance with GR.3.1.2(d).
Part 1 System Ancillary
Services
Ancillary Services which are required for System reasons and which
must be provided by Users in accordance with the Connection
Conditions. An exhaustive list of Part 1 System Ancillary Services is
included in that part of CC.8.1 headed Part 1.
Part 2 System Ancillary
Services
Ancillary Services which are required for System reasons and which
must be provided by a User if the User has agreed to provide them
under a Bilateral Agreement. A non-exhaustive list of Part 2 System
Ancillary Services is included in that part of CC.8.1 headed Part 2.
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Part Load
The condition of a Genset, or Cascade Hydro Scheme which is Loaded
but is not running at its Maximum Export Limit.
Permit for Work for
proximity work
In respect of E&W Transmission Systems, a document issued by the
Relevant E&W Transmission Licensee or an E&W User in accordance
with its respective Safety Rules to enable work to be carried out in
accordance with OC8A.8 and which provides for Safety Precautions to
be applied and maintained. An example format of a Relevant E&W
Transmission Licensee’s permit for work is attached as Appendix E to
OC8A.
In respect of Scottish Transmission Systems, a document issued by a
Relevant Scottish Transmission Licensee or a Scottish User in
accordance with its respective Safety Rules to enable work to be carried
out in accordance with OC8B.8 and which provides for Safety
Precautions to be applied and maintained. Example formats of Relevant
Scottish Transmission Licensees’ permits for work are attached as
Appendix E to OC8B.
Partial Shutdown
The same as a Total Shutdown except that all generation has ceased in
a separate part of the Total System and there is no electricity supply
from External Interconnections or other parts of the Total System to
that part of the Total System and, therefore, that part of the Total
System is shutdown, with the result that it is not possible for that part of
the Total System to begin to function again without NGET’s directions
relating to a Black Start.
Pending Grid Code
Modification Proposal
A Grid Code Modification Proposal in respect of which, at the relevant
time, the Authority has not yet made a decision as to whether to direct
such Grid Code Modification Proposal to be made pursuant to the
Transmission Licence (whether or not a Grid Code Modification
Report has been submitted in respect of such Grid Code Modification
Proposal) or, in the case of a Grid Code Self Governance Proposals,
in respect of which the Grid Code Review Panel has not yet voted
whether or not to approve.
Phase (Voltage)
Unbalance
The ratio (in percent) between the rms values of the negative sequence
component and the positive sequence component of the voltage.
Physical Notification
Data that describes the BM Participant’s best estimate of the expected
input or output of Active Power of a BM Unit and/or (where relevant)
Generating Unit, the accuracy of the Physical Notification being
commensurate with Good Industry Practice.
Planning Code or PC
That portion of the Grid Code which is identified as the Planning Code.
Planned Maintenance
Outage
An outage of NGET electronic data communication facilities as provided
for in CC.6.5.8 and NGET’s associated computer facilities of which
normally at least 5 days notice is given, but in any event of which at least
twelve hours notice has been given by NGET to the User and which is
anticipated to last no longer than 2 hours. The length of such an outage
may in exceptional circumstances be extended where at least 24 hours
notice has been given by NGET to the User. It is anticipated that
normally any planned outage would only last around one hour.
Planned Outage
An outage of a Large Power Station or of part of the National
Electricity Transmission System, or of part of a User System, coordinated by NGET under OC2.
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Plant
Fixed and movable items used in the generation and/or supply and/or
transmission of electricity, other than Apparatus.
Point of Common
Coupling
That point on the National Electricity Transmission System electrically
nearest to the User installation at which either Demands or Loads are,
or may be, connected.
Point of Connection
An electrical point of connection between the National Electricity
Transmission System and a User’s System.
Point of Isolation
The point on Apparatus (as defined in OC8A.1.6.2 and OC8B.1.7.2) at
which Isolation is achieved.
Post-Control Phase
The period following real time operation.
Power Available
A signal prepared in accordance with good industry practice,
representing the instantaneous sum of the potential Active Power
available from each individual Power Park Unit within the Power Park
Module calculated using any applicable combination of meteorological
(including wind speed), electrical or mechanical data measured at each
Power Park Unit at a specified time. Power Available shall be a value
between 0MW and Registered Capacity which is the sum of the
potential Active Power available of each Power Park Unit within the
Power Park Module. A turbine that is not generating will be considered
as not available. For the avoidance of doubt, the Power Available signal
would be the Active Power output that a Power Park Module could
reasonably be expected to export at the Grid Entry Point or User
System Entry Point taking all the above criteria into account including
Power Park Unit constraints such as optimisation modes but would
exclude a reduction in the Active Power export of the Power Park
Module instructed by NGET (for example) for the purposes selecting a
Power Park Module to operate in Frequency Sensitive Mode or when
an Emergency Instruction has been issued.
Power Factor
The ratio of Active Power to Apparent Power.
Power Island
Gensets at an isolated Power Station, together with complementary
local Demand. In Scotland a Power Island may include more than one
Power Station.
Power Park Module
Any Onshore Power Park Module or Offshore Power Park Module.
Power Park Module
Availability Matrix
The matrix described in Appendix 1 to BC1 under the heading Power
Park Module Availability Matrix .
Power Park Module
Planning Matrix
A matrix in the form set out in Appendix 4 of OC2 showing the
combination of Power Park Units within a Power Park Module which
would be expected to be running under normal conditions.
Power Park Unit
A Generating Unit within a Power Park Module.
Power Station
An installation comprising one or more Generating Units or Power Park
Modules (even where sited separately) owned and/or controlled by the
same Generator, which may reasonably be considered as being
managed as one Power Station.
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Power System Stabiliser
or PSS
Equipment controlling the Exciter output via the voltage regulator in such
a way that power oscillations of the synchronous machines are
dampened. Input variables may be speed, frequency or power (or a
combination of these).
Preface
The preface to the Grid Code (which does not form part of the Grid Code
and therefore is not binding).
Preliminary Notice
A notice in writing, sent by NGET both to all Users identified by it under
OC12.4.2.1 and to the Test Proposer, notifying them of a proposed
System Test.
Preliminary Project
Planning Data
Data relating to a proposed User Development at the time the User
applies for a CUSC Contract but before an offer is made and accepted.
Primary Response
The automatic increase in Active Power output of a Genset or, as the
case may be, the decrease in Active Power Demand in response to a
System Frequency fall. This increase in Active Power output or, as the
case may be, the decrease in Active Power Demand must be in
accordance with the provisions of the relevant Ancillary Services
Agreement which will provide that it will be released increasingly with
time over the period 0 to 10 seconds from the time of the start of the
Frequency fall on the basis set out in the Ancillary Services
Agreement and fully available by the latter, and sustainable for at least a
further 20 seconds. The interpretation of the Primary Response to a –
0.5 Hz frequency change is shown diagrammatically in Figure CC.A.3.2.
Programming Phase
The period between Operational Planning Phase and the Control
Phase. It starts at the 8 weeks ahead stage and finishes at 17:00 on the
day ahead of real time.
Proposal Notice
A notice submitted to NGET by a User which would like to undertake a
System Test.
Proposal Report
A report submitted by the Test Panel which contains:
(a)
proposals for carrying out a System Test (including the manner in
which the System Test is to be monitored);
(b)
an allocation of costs (including un-anticipated costs) between the
affected parties (the general principle being that the Test
Proposer will bear the costs); and
(c)
such other matters as the Test Panel considers appropriate.
The report may include requirements for indemnities to be given in
respect of claims and losses arising from a System Test.
Proposed
Implementation Date
The proposed date(s) for the implementation of a Grid Code
Modification Proposal or Workgroup Alternative Grid Code
Modification such date(s) to be either (i) described by reference to a
specified period after a direction from the Authority approving the Grid
Code Modification Proposal or Workgroup Alternative Grid Code
Modification or (ii) a Fixed Proposed Implementation Date .
Protection
The provisions for detecting abnormal conditions on a System and
initiating fault clearance or actuating signals or indications.
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Protection Apparatus
A group of one or more Protection relays and/or logic elements
designated to perform a specified Protection function.
Pumped Storage
Generator
A Generator which owns and/or operates any Pumped Storage Plant.
Pumped Storage Plant
The Dinorwig, Ffestiniog, Cruachan and Foyers Power Stations.
Pumped Storage Unit
A Generating Unit within a Pumped Storage Plant.
Quiescent Physical
Notification or QPN
Data that describes the MW levels to be deducted from the Physical
Notification of a BM Unit to determine a resultant operating level to
which the Dynamic Parameters associated with that BM Unit apply, and
the associated times for such MW levels. The MW level of the QPN must
always be set to zero.
Range CCGT Module
A CCGT Module where there is a physical connection by way of a steam
or hot gas main between that CCGT Module and another CCGT Module
or other CCGT Modules, which connection contributes (if open) to
efficient modular operation, and which physical connection can be varied
by the operator.
Rated Field Voltage
Shall have the meaning ascribed to that term in IEC 34-16-1:1991
[equivalent to British Standard BS4999 Section 116.1 : 1992].
Rated MW
The “rating-plate” MW output of a Generating Unit, Power Park Module
or DC Converter, being:
(a)
that output up to which the Generating Unit was designed to
operate (Calculated as specified in British Standard BS EN
60034 – 1: 1995); or
(b)
the nominal rating for the MW output of a Power Park Module
being the maximum continuous electric output power which the
Power Park Module was designed to achieve under normal
operating conditions; or
(c)
the nominal rating for the MW import capacity and export capacity
(if at a DC Converter Station) of a DC Converter.
Reactive Despatch
Instruction
Has the meaning set out in the CUSC.
Reactive Despatch
Network Restriction
A restriction placed upon an Embedded Generating Unit, Embedded
Power Park Module or DC Converter at an Embedded DC Converter
Station by the Network Operator that prevents the Generator or DC
Converter Station owner in question (as applicable) from complying with
any Reactive Despatch Instruction with respect to that Generating
Unit, Power Park Module or DC Converter at a DC Converter Station,
whether to provide Mvars over the range referred to in CC 6.3.2 or
otherwise.
Reactive Energy
The integral with respect to time of the Reactive Power.
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Reactive Power
The product of voltage and current and the sine of the phase angle
between them measured in units of voltamperes reactive and standard
multiples thereof, ie:
1000 VAr = 1 kVAr
1000 kVAr = 1 Mvar
Record of Inter-System
Safety Precautions or
RISSP
A written record of inter-system Safety Precautions to be compiled in
accordance with the provisions of OC8.
Registered Capacity
(a)
In the case of a Generating Unit other than that forming part of a
CCGT Module or Power Park Module, the normal full load
capacity of a Generating Unit as declared by the Generator, less
the MW consumed by the Generating Unit through the
Generating Unit’s Unit Transformer when producing the same
(the resultant figure being expressed in whole MW, or in MW to
one decimal place).
(b)
In the case of a CCGT Module or Power Park Module, the normal
full load capacity of the CCGT Module or Power Park Module (as
the case may be) as declared by the Generator, being the Active
Power declared by the Generator as being deliverable by the
CCGT Module or Power Park Module at the Grid Entry Point (or
in the case of an Embedded CCGT Module or Power Park
Module, at the User System Entry Point), expressed in whole
MW, or in MW to one decimal place.
(c)
In the case of a Power Station, the maximum amount of Active
Power deliverable by the Power Station at the Grid Entry Point
(or in the case of an Embedded Power Station at the User
System Entry Point), as declared by the Generator, expressed in
whole MW, or in MW to one decimal place. The maximum Active
Power deliverable is the maximum amount deliverable
simultaneously by the Generating Units and/or CCGT Modules
and/or Power Park Modules less the MW consumed by the
Generating Units and/or CCGT Modules in producing that Active
Power.
(d)
In the case of a DC Converter at a DC Converter Station, the
normal full load amount of Active Power transferable from a DC
Converter at the Onshore Grid Entry Point (or in the case of an
Embedded DC Converter Station at the User System Entry
Point), as declared by the DC Converter Station owner,
expressed in whole MW, or in MW to one decimal place.
(e)
In the case of a DC Converter Station, the maximum amount of
Active Power transferable from a DC Converter Station at the
Onshore Grid Entry Point (or in the case of an Embedded DC
Converter Station at the User System Entry Point), as declared
by the DC Converter Station owner, expressed in whole MW, or
in MW to one decimal place.
Registered Data
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Those items of Standard Planning Data and Detailed Planning Data
which upon connection become fixed (subject to any subsequent
changes).
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Registered Import
Capability
In the case of a DC Converter Station containing DC Converters
connected to an External System, the maximum amount of Active
Power transferable into a DC Converter Station at the Onshore Grid
Entry Point (or in the case of an Embedded DC Converter Station at
the User System Entry Point), as declared by the DC Converter
Station owner, expressed in whole MW.
In the case of a DC Converter connected to an External System and in
a DC Converter Station, the normal full load amount of Active Power
transferable into a DC Converter at the Onshore Grid Entry Point (or in
the case of an Embedded DC Converter Station at the User System
Entry Point), as declared by the DC Converter owner, expressed in
whole MW.
Regulations
The Utilities Contracts Regulations 1996, as amended from time to time.
Reheater Time Constant
Determined at Registered Capacity, the reheater time constant will be
construed in accordance with the principles of the IEEE Committee
Report "Dynamic Models for Steam and Hydro Turbines in Power System
Studies" published in 1973 which apply to such phrase.
Rejected Grid Code
Modification Proposal
A Grid Code Modification Proposal in respect of which the Authority
has decided not to direct The Company to modify the Grid Code
pursuant to the Transmission Licence in the manner set out herein or,
in the case of a Grid Code Self Governance Proposals, in respect of
which the Grid Code Review Panel has voted not to approve.
Related Person
means, in relation to an individual, any member of his immediate family,
his employer (and any former employer of his within the previous 12
months), any partner with whom he is in partnership, and any company
or Affiliate of a company in which he or any member of his immediate
family controls more than 20% of the voting rights in respect of the
shares of the company;
Relevant E&W
Transmission Licensee
As the context requires NGET and/or an E&W Offshore Transmission
Licensee.
Relevant Party
Has the meaning given in GR15.10(a).
Relevant Scottish
Transmission Licensee
As the context requires SPT and/or SHETL and/or a Scottish Offshore
Transmission Licensee.
Relevant Transmission
Licensee
Means SP Transmission Ltd (SPT) in its Transmission Area or Scottish
Hydro-Electric Transmission Ltd (SHETL) in its Transmission Area or
any Offshore Transmission Licensee in its Transmission Area.
Relevant Unit
As defined in the STC, Schedule 3.
Remote Transmission
Assets
Any Plant and Apparatus or meters owned by NGET which:
Requesting Safety Coordinator
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(a)
are Embedded in a User System and which are not directly
connected by Plant and/or Apparatus owned by NGET to a substation owned by NGET; and
(b)
are by agreement between NGET and such User operated under
the direction and control of such User.
The Safety Co-ordinator requesting Safety Precautions.
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Responsible Engineer/
Operator
A person nominated by a User to be responsible for System control.
Responsible Manager
A manager who has been duly authorised by a User or NGET to sign
Site Responsibility Schedules on behalf of that User or NGET, as the
case may be.
For Connection Sites in Scotland and Offshore a manager who has
been duly authorised by the Relevant Transmission Licensee to sign
Site Responsibility Schedules on behalf of that Relevant
Transmission Licensee.
Re-synchronisation
The bringing of parts of the System which have become Out of
Synchronism with any other System back into Synchronism, and like
terms shall be construed accordingly.
Safety Co-ordinator
A person or persons nominated by a Relevant E&W Transmission
Licensee and each E&W User in relation to Connection Points (or in
the case of OTSUA operational prior to the OTSUA Transfer Time,
Transmission Interface Points) on an E&W Transmission System
and/or by the Relevant Scottish Transmission Licensee and each
Scottish User in relation to Connection Points (or in the case of
OTSUA operational prior to the OTSUA Transfer Time, Transmission
Interface Points) on a Scottish Transmission System to be
responsible for the co-ordination of Safety Precautions at each
Connection Point (or in the case of OTSUA operational prior to the
OTSUA Transfer Time, Transmission Interface Points) when work
(which includes testing) is to be carried out on a System which
necessitates the provision of Safety Precautions on HV Apparatus (as
defined in OC8A.1.6.2 and OC8B.1.7.2), pursuant to OC8.
Safety From The System That condition which safeguards persons when work is to be carried out
on or near a System from the dangers which are inherent in the System.
Safety Key
A key unique at the Location capable of operating a lock which will
cause an Isolating Device and/or Earthing Device to be Locked.
Safety Log
A chronological record of messages relating to safety co-ordination sent
and received by each Safety Co-ordinator under OC8.
Safety Precautions
Isolation and/or Earthing.
Safety Rules
The rules of NGET (in England and Wales) and the Relevant
Transmission Licensee (in Scotland or Offshore) or a User that seek to
ensure that persons working on Plant and/or Apparatus to which the
rules apply are safeguarded from hazards arising from the System.
Scottish Offshore
Transmission System
An Offshore Transmission System with an Interface Point in Scotland.
Scottish Offshore
Transmission Licensee
A person who owns or operates a Scottish Offshore Transmission
System pursuant to a Transmission Licence.
Scottish Transmission
System
Collectively SPT’s Transmission System and SHETL’s Transmission
System and any Scottish Offshore Transmission Systems.
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Scottish User
A User in Scotland or any Offshore User who owns or operates Plant
and/or Apparatus connected (or which will at the OTSUA Transfer Time
be connected) to a Scottish Offshore Transmission System
Secondary Response
The automatic increase in Active Power output of a Genset or, as the
case may be, the decrease in Active Power Demand in response to a
System Frequency fall. This increase in Active Power output or, as the
case may be, the decrease in Active Power Demand must be in
accordance with the provisions of the relevant Ancillary Services
Agreement which will provide that it will be fully available by 30 seconds
from the time of the start of the Frequency fall and be sustainable for at
least a further 30 minutes. The interpretation of the Secondary
Response to a -0.5 Hz frequency change is shown diagrammatically in
Figure CC.A.3.2.
Secretary of State
Has the same meaning as in the Act.
Secured Event
Has the meaning set out in the Security and Quality of Supply
Standard.
Security and Quality of
Supply Standard
The version of the document entitled ‘Security and Quality of Supply
Standard’ established pursuant to the Transmission Licence in force at
the time of entering into the relevant Bilateral Agreement.
Self-Governance
Criteria
A proposed Modification that, if implemented,
(a) is unlikely to have a material effect on:
(i)
existing or future electricity consumers; and
(ii)
competition in the generation, distribution, or supply of electricity
or any commercial activities connected with the generation,
distribution or supply of electricity; and
(iii)
the operation of the National Electricity Transmission System;
and
(iv)
matters relating to sustainable development, safety or security of
supply, or the management of market or network emergencies;
and
(v)
the Grid Code’s governance procedures or the Grid Code’s
modification procedures, and
(b) is unlikely to discriminate between different classes of Users.
Self-Governance
Modifications
A Grid Code Modification Proposal that does not fall within the scope
of a Significant Code Review and that meets the Self-Governance
Criteria or which the Authority directs is to be treated as such any
direction under GR.24.4.
Self-Governance
Statement
The statement made by the Grid Code Review Panel and submitted to
the Authority:
(a) confirming that, in its opinion, the Self-Governance Criteria are met
and the proposed Grid Code Modification Proposal is suitable for the
Self-Governance route; and
(b) providing a detailed explanation of the Grid Code Review Panel’s
reasons for that opinion
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Setpoint Voltage
The value of voltage at the Grid Entry Point, or User System Entry
Point if Embedded, on the automatic control system steady state
operating characteristic, as a percentage of the nominal voltage, at which
the transfer of Reactive Power between a Power Park Module, DC
Converter or Non-Synchronous Generating Unit and the
Transmission System, or Network Operator’s system if Embedded, is
zero.
Settlement Period
A period of 30 minutes ending on the hour and half-hour in each hour
during a day.
Seven Year Statement
A statement, prepared by NGET in accordance with the terms of NGET’s
Transmission Licence, showing for each of the seven succeeding
Financial Years, the opportunities available for connecting to and using
the National Electricity Transmission System and indicating those
parts of the National Electricity Transmission System most suited to
new connections and transport of further quantities of electricity.
SF6 Gas Zone
A segregated zone surrounding electrical conductors within a casing
containing SF6 gas.
SHETL
Scottish Hydro-Electric Transmission Limited
Shutdown
The condition of a Generating Unit where the generator rotor is at rest or
on barring.
Significant Code Review
Means the period commencing on the start date of a Significant Code
Review as stated in the notice issued by the Authority, and ending in
the circumstances described in GR.16.6 or GR.16.7, as appropriate.
Significant Code Review
Phase
Means the period commencing on the start date of a Significant Code
Review as stated in the notice issued by the Authority, and ending in
the circumstances described in GR.16.6 or GR.16.7, as appropriate.
Significant Incident
An Event which either:
Simultaneous Tap
Change
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(a)
was notified by a User to NGET under OC7, and which NGET
considers has had or may have had a significant effect on the
National Electricity Transmission System, and NGET requires
the User to report that Event in writing in accordance with OC10
and notifies the User accordingly; or
(b)
was notified by NGET to a User under OC7, and which that User
considers has had or may have had a significant effect on that
User’s System, and that User requires NGET to report that Event
in writing in accordance with the provisions of OC10 and notifies
NGET accordingly.
A tap change implemented on the generator step-up transformers of
Synchronised Gensets, effected by Generators in response to an
instruction from NGET issued simultaneously to the relevant Power
Stations. The instruction, preceded by advance notice, must be effected
as soon as possible, and in any event within one minute of receipt from
NGET of the instruction.
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Single Line Diagram
A schematic representation of a three-phase network in which the three
phases are represented by single lines. The diagram shall include (but
not necessarily be limited to) busbars, overhead lines, underground
cables, power transformers and reactive compensation equipment. It
shall also show where Large Power Stations are connected, and the
points at which Demand is supplied.
Single Point of
Connection
A single Point of Connection, with no interconnection through the
User’s System to another Point of Connection.
Site Common Drawings
Drawings prepared for each Connection Site (and in the case of
OTSDUW, Transmission Interface Site) which incorporate Connection
Site (and in the case of OTSDUW, Transmission Interface Site) layout
drawings, electrical layout drawings, common protection/ control
drawings and common services drawings.
Site Responsibility
Schedule
A schedule containing the information and prepared on the basis of the
provisions set out in Appendix 1 of the CC.
Slope
The ratio of the steady state change in voltage, as a percentage of the
nominal voltage, to the steady state change in Reactive Power output, in
per unit of Reactive Power capability. For the avoidance of doubt, the
value indicates the percentage voltage reduction that will result in a 1 per
unit increase in Reactive Power generation.
Small Participant
Has the meaning given in the CUSC.
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Small Power Station
A Power Station which is
(a)
directly connected to:
(i)
NGET’s Transmission System where such Power Station
has a Registered Capacity of less than 50MW; or
(ii)
SPT’s Transmission System where such Power Station
has a Registered Capacity of less than 30MW; or
(iii)
SHETL’s Transmission System where such a Power
Station has a Registered Capacity of less than 10 MW; or
(iv)
an Offshore Transmission System where such Power
Station has a Registered Capacity of less than 10MW;
or,
(b)
Embedded within a User System (or part thereof) where such
User System (or part thereof) is connected under normal
operating conditions to:
(i)
NGET’s Transmission System and such Power Station
has a Registered Capacity of less than 50MW; or
(ii)
SPT’s Transmission System and such Power Station has
a Registered Capacity of less than 30MW; or
(iii)
SHETL’s Transmission System and such Power Station
has a Registered Capacity of less than 10MW;
or,
(c)
Embedded within a User System (or part thereof) where the User
System (or part thereof) is not connected to the National
Electricity Transmission System, although such Power Station
is in:
(i)
NGET’s Transmission Area and such Power Station has
a Registered Capacity of less than 50MW; or
(ii)
SPT’s Transmission Area and such Power Station has a
Registered Capacity of less than 30MW; or
(iii)
SHETL’s Transmission Area and such Power Station has
a Registered Capacity of less than 10MW;
Speeder Motor Setting
Range
The minimum and maximum no-load speeds (expressed as a percentage
of rated speed) to which the turbine is capable of being controlled, by the
speeder motor or equivalent, when the Generating Unit terminals are on
open circuit.
SPT
SP Transmission Limited
Standard Modifications
A Grid Code Modification Proposal that does not fall within the scope
of a Significant Code Review subject to any direction by the Authority
pursuant to GR.16.3 and GR.16.4, nor meets the Self-Governance
Criteria subject to any direction by the Authority pursuant to GR.24.4
and in accordance with any direction under GR.24.2.
Standard Planning Data
The general data required by NGET under the PC. It is generally also the
data which NGET requires from a new User in an application for a CUSC
Contract, as reflected in the PC.
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Start Time
The time named as such in an instruction issued by NGET pursuant to
the BC.
Start-Up
The action of bringing a Generating Unit from Shutdown to
Synchronous Speed.
Statement of Readiness
Has the meaning set out in the Bilateral Agreement and/or
Construction Agreement.
Station Board
A switchboard through which electrical power is supplied to the
Auxiliaries of a Power Station, and which is supplied by a Station
Transformer. It may be interconnected with a Unit Board.
Station Transformer
A transformer supplying electrical power to the Auxiliaries of
(a)
a Power Station, which is not directly connected to the
Generating Unit terminals (typical voltage ratios being 132/11kV
or 275/11kV),or
(b)
a DC Converter Station.
STC Committee
The committee established under the STC.
Steam Unit
A Generating Unit whose prime mover converts the heat-energy in
steam to mechanical energy.
Subtransmission
System
The part of a User’s System which operates at a single transformation
below the voltage of the relevant Transmission System.
Supergrid Voltage
Any voltage greater than 200kV.
Supplier
(a)
A person supplying electricity under an Electricity Supply
Licence; or
(b)
A person supplying electricity under exemption under the Act;
in each case acting in its capacity as a supplier of electricity to
Customers in Great Britain.
Surplus
A MW figure relating to a System Zone equal to the total Output Usable
in the System Zone:
(a)
minus the forecast of Active Power Demand in the System Zone,
and
(b)
minus the export limit in the case of an export limited System
Zone,
or
plus the import limit in the case of an import limited System Zone,
and
(c)
(only in the case of a System Zone comprising the National
Electricity Transmission System) minus the Operational
Planning Margin.
For the avoidance of doubt, a Surplus of more than zero in an export
limited System Zone indicates an excess of generation in that System
Zone; and a Surplus of less than zero in an import limited System Zone
indicates insufficient generation in that System Zone.
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Synchronised
(a)
The condition where an incoming Generating Unit or Power Park
Module or DC Converter or System is connected to the busbars
of another System so that the Frequencies and phase
relationships of that Generating Unit, Power Park Module, DC
Converter or System, as the case may be, and the System to
which it is connected are identical, like terms shall be construed
accordingly e.g. “Synchronism”.
(b)
The condition where an importing BM Unit is consuming electricity.
Synchronising
Generation
The amount of MW (in whole MW) produced at the moment of
synchronising.
Synchronising Group
A group of two or more Gensets) which require a minimum time interval
between their Synchronising or De-Synchronising times.
Synchronous
Compensation
The operation of rotating synchronous Apparatus for the specific
purpose of either the generation or absorption of Reactive Power.
Synchronous
Generating Unit
Any Onshore Synchronous
Synchronous Generating Unit.
Synchronous Speed
That speed required by a Generating Unit to enable it to be
Synchronised to a System.
System
Any User System and/or the National Electricity Transmission
System, as the case may be.
System Ancillary
Services
Collectively Part 1 System Ancillary Services and Part 2 System
Ancillary Services.
System Constraint
A limitation on the use of a System due to lack of transmission capacity
or other System conditions.
System Constrained
Capacity
That portion of Registered Capacity or Registered Import Capacity not
available due to a System Constraint.
System Constraint
Group
A part of the National Electricity Transmission System which, because
of System Constraints, is subject to limits of Active Power which can
flow into or out of (as the case may be) that part.
System Fault
Dependability Index or
Dp
A measure of the ability of Protection to initiate successful tripping of
circuit-breakers which are associated with a faulty item of Apparatus. It
is calculated using the formula:
Generating
Unit
or
Offshore
Dp = 1 – F1/A
Where:
A = Total number of System faults
F1 = Number of System faults where there was a failure to trip a
circuit-breaker.
System Margin
The margin in any period between
(a)
the sum of Maximum Export Limits and
(b)
forecast Demand and the Operating Margin,
for that period.
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System Negative
Reserve Active Power
Margin or System
NRAPM
That margin of Active Power sufficient to allow the largest loss of Load
at any time.
System Operator Transmission Owner
Code or STC
Has the meaning set out in NGET’s Transmission Licence
System Telephony
An alternative method by which a User’s Responsible
Engineer/Operator and NGET Control Engineer(s) speak to one and
another for the purposes of control of the Total System in both normal
operating conditions and where practicable, emergency operating
conditions.
System Tests
Tests which involve simulating conditions, or the controlled application of
irregular, unusual or extreme conditions, on the Total System, or any
part of the Total System, but which do not include commissioning or
recommissioning tests or any other tests of a minor nature.
System to Demand
Intertrip Scheme
An intertrip scheme which disconnects Demand when a System fault
has arisen to prevent abnormal conditions occurring on the System.
System to Generator
Operational
Intertripping
A Balancing Service involving the initiation by a System to Generator
Operational Intertripping Scheme of automatic tripping of the User’s
circuit breaker(s), or Relevant Transmission Licensee’s circuit
breaker(s) where agreed by NGET, the User and the Relevant
Transmission Licensee, resulting in the tripping of BM Unit(s) or
(where relevant) Generating Unit(s) comprised in a BM Unit to prevent
abnormal system conditions occurring, such as over voltage, overload,
System instability, etc, after the tripping of other circuit-breakers
following power System fault(s).
System to Generator
Operational
Intertripping Scheme
A System to Generating Unit or System to CCGT Module or System to
Power Park Module Intertripping Scheme forming a condition of
connection and specified in Appendix F3 of the relevant Bilateral
Agreement, being either a Category 1 Intertripping Scheme, Category 2
Intertripping Scheme, Category 3 Intertripping Scheme or Category 4
Intertripping Scheme.
System Zone
A region of the National Electricity Transmission System within a
described boundary or the whole of the National Electricity
Transmission System, as further provided for in OC2.2.4, and the term
"Zonal" will be construed accordingly.
Target Frequency
That Frequency determined by NGET, in its reasonable opinion, as the
desired operating Frequency of the Total System. This will normally be
50.00Hz plus or minus 0.05Hz, except in exceptional circumstances as
determined by NGET, in its reasonable opinion when this may be 49.90
or 50.10Hz. An example of exceptional circumstances may be difficulties
caused in operating the System during disputes affecting fuel supplies.
Technical Specification
In relation to Plant and/or Apparatus,
Issue 5 Revision 20
(a)
the relevant European Specification; or
(b)
if there is no relevant European Specification, other relevant
standards which are in common use in the European Community.
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Test Co-ordinator
A person who co-ordinates System Tests.
Test Panel
A panel, whose composition is detailed in OC12, which is responsible,
inter alia, for considering a proposed System Test, and submitting a
Proposal Report and a Test Programme.
Test Programme
A programme submitted by the Test Panel to NGET, the Test Proposer,
and each User identified by NGET under OC12.4.2.1, which states the
switching sequence and proposed timings of the switching sequence, a
list of those staff involved in carrying out the System Test (including
those responsible for the site safety) and such other matters as the Test
Panel deems appropriate.
Test Proposer
The person who submits a Proposal Notice.
Total Shutdown
The situation existing when all generation has ceased and there is no
electricity supply from External Interconnections and, therefore, the
Total System has shutdown with the result that it is not possible for the
Total System to begin to function again without NGET’s directions
relating to a Black Start.
Total System
The National Electricity Transmission System and all User Systems
in the National Electricity Transmission System Operator Area .
Trading Point
A commercial and, where so specified in the Grid Code, an operational
interface between a User and NGET, which a User has notified to NGET.
Transfer Date
Such date as may be appointed by the Secretary of State by order
under section 65 of the Act.
Transmission
Means, when used in conjunction with another term relating to equipment
or a site, whether defined or not, that the associated term is to be read as
being part of or directly associated with the National Electricity
Transmission System, and not of or with the User System.
Transmission Area
Has the meaning set out in the Transmission Licence of a
Transmission Licensee.
Transmission DC
Converter
Any Transmission Licensee Apparatus (or OTSUA that will become
Transmission Licensee Apparatus at the OTSUA Transfer Time) used
to convert alternating current electricity to direct current electricity, or vice
versa. A Transmission Network DC Converter is a standalone
operative configuration at a single site comprising one or more converter
bridges, together with one or more converter transformers, converter
control equipment, essential protective and switching devices and
auxiliaries, if any, used for conversion.
Transmission Entry
Capacity
Has the meaning set out in the CUSC.
Transmission Interface
Circuit
In NGET’s Transmission Area, a Transmission circuit which connects
a System operating at a voltage above 132kV to a System operating at
a voltage of 132kV or below
In SHETL’s Transmission Area and SPT’s Transmission Area, a
Transmission circuit which connects a System operating at a voltage of
132kV or above to a System operating at a voltage below 132kV.
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Transmission Interface
Point
means the electrical point of connection between the Offshore
Transmission System and an Onshore Transmission System.
Transmission Interface
Site
the site at which the Transmission Interface Point is located.
Transmission Licence
A licence granted under Section 6(1)(b) of the Act.
Transmission Licensee
Any Onshore Transmission Licensee or Offshore Transmission
Licensee
Transmission Site
In England and Wales, means a site owned (or occupied pursuant to a
lease, licence or other agreement) by NGET in which there is a
Connection Point. For the avoidance of doubt, a site owned by a User
but occupied by NGET as aforesaid, is a Transmission Site.
In Scotland and Offshore, means a site owned (or occupied pursuant to
a lease, licence or other agreement) by a Relevant Transmission
Licensee in which there is a Connection Point. For the avoidance of
doubt, a site owned by a User but occupied by the Relevant
Transmission Licensee as aforesaid, is a Transmission Site.
Transmission System
Has the same meaning as the term "licensee's transmission system" in
the Transmission Licence of a Transmission Licensee.
Turbine Time Constant
Determined at Registered Capacity, the turbine time constant will be
construed in accordance with the principles of the IEEE Committee
Report "Dynamic Models for Steam and Hydro Turbines in Power System
Studies" published in 1973 which apply to such phrase.
Unbalanced Load
The situation where the Load on each phase is not equal.
Under-excitation Limiter
Shall have the meaning ascribed to that term in IEC 34-16-1:1991
[equivalent to British Standard BS4999 Section 116.1 : 1992].
Under Frequency Relay
An electrical measuring relay intended to operate when its characteristic
quantity (Frequency) reaches the relay settings by decrease in
Frequency.
Unit Board
A switchboard through which electrical power is supplied to the
Auxiliaries of a Generating Unit and which is supplied by a Unit
Transformer. It may be interconnected with a Station Board.
Unit Transformer
A transformer directly connected to a Generating Unit’s terminals, and
which supplies power to the Auxiliaries of a Generating Unit. Typical
voltage ratios are 23/11kV and 15/6.6Kv.
Unit Load Controller
Response Time
Constant
The time constant, expressed in units of seconds, of the power output
increase which occurs in the Secondary Response timescale in
response to a step change in System Frequency.
Unresolved Issues
Any relevant Grid Code provisions or Bilateral Agreement requirements
identified by NGET with which the relevant User has not demonstrated
compliance to NGET’s reasonable satisfaction at the date of issue of the
Interim Operational Notification and/or Limited Operational
Notification and which are detailed in such Interim Operational
Notification and/or Limited Operational Notification.
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Urgent Modification
A Grid Code Modification Proposal treated or to be treated as an
Urgent Modification in accordance with GR.23.
User
A term utilised in various sections of the Grid Code to refer to the persons
using the National Electricity Transmission System, as more
particularly identified in each section of the Grid Code concerned. In the
Preface and the General Conditions the term means any person to
whom the Grid Code applies.
User Data File Structure
The file structure given at DRC 18 which will be specified by NGET which
a Generator or DC Converter Station owner must use for the purposes
of CP to submit DRC data Schedules and information demonstrating
compliance with the Grid Code and, where applicable, with the CUSC
Contract(s), unless otherwise agreed by NGET.
User Development
In the PC means either User's Plant and/or Apparatus to be connected
to the National Electricity Transmission System, or a Modification
relating to a User's Plant and/or Apparatus already connected to the
National Electricity Transmission System, or a proposed new
connection or Modification to the connection within the User System.
User Self Certification of A certificate, in the form attached at CP.A.2.(1) completed by a Generator
Compliance
or DC Converter Station owner to which the Compliance Statement is
attached which confirms that such Plant and Apparatus complies with the
relevant Grid Code provisions and where appropriate, with the CUSC
Contract(s), as identified in the Compliance Statement and, if
appropriate, identifies any Unresolved Issues and/or any exceptions to
such compliance and details the derogation(s) granted in respect of such
exceptions.
User Site
In England and Wales, a site owned (or occupied pursuant to a lease,
licence or other agreement) by a User in which there is a Connection
Point. For the avoidance of doubt, a site owned by NGET but occupied
by a User as aforesaid, is a User Site.
In Scotland and Offshore, a site owned (or occupied pursuant to a lease,
licence or other agreement) by a User in which there is a Connection
Point. For the avoidance of doubt, a site owned by a Relevant
Transmission Licensee but occupied by a User as aforesaid, is a User
Site.
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User System
Any system owned or operated by a User comprising:(a)
Generating Units; and/or
(b)
Systems consisting (wholly or mainly) of electric lines used for the
distribution of electricity from Grid Supply Points or Generating
Units or other entry points to the point of delivery to Customers,
or other Users;
and Plant and/or Apparatus Apparatus (including prior to the OTSUA
Transfer Time, any OTSUA) connecting:(c)
The system as described above; or
(d)
Non-Embedded Customers equipment;
to the National Electricity Transmission System or to the relevant
other User System, as the case may be.
The User System includes any Remote Transmission Assets operated
by such User or other person and any Plant and/or Apparatus and
meters owned or operated by the User or other person in connection with
the distribution of electricity but does not include any part of the National
Electricity Transmission System.
User System Entry Point A point at which a Generating Unit, a CCGT Module or a CCGT Unit or
a Power Park Module or a DC Converter, as the case may be, which is
Embedded connects to the User System.
Water Time Constant
Bears the meaning ascribed to the term "Water inertia time" in IEC308.
Website
The site established by NGET on the World-Wide Web for the exchange
of information among Users and other interested persons in accordance
with such restrictions on access as may be determined from time to time
by NGET.
Weekly ACS Conditions
Means that particular combination of weather elements that gives rise to
a level of peak Demand within a week, taken to commence on a Monday
and end on a Sunday, which has a particular chance of being exceeded
as a result of weather variation alone. This particular chance is
determined such that the combined probabilities of Demand in all weeks
of the year exceeding the annual peak Demand under Annual ACS
Conditions is 50%, and in the week of maximum risk the weekly peak
Demand under Weekly ACS Conditions is equal to the annual peak
Demand under Annual ACS Conditions.
WG Consultation
Alternative Request
Any request from an Authorised Electricity Operator; the Citizens
Advice or the Citizens Advice Scotland, NGET or a Materially
Affected Party for a Workgroup Alternative Grid Code Modification to
be developed by the Workgroup expressed as such and which contains
the information referred to at GR.20.13. For the avoidance of doubt any
WG Consultation Alternative Request does not constitute either a Grid
Code Modification Proposal or a Workgroup Alternative Grid Code
Modification
Workgroup
Workgroup
Consultation
Issue 5 Revision 20
a Workgroup established by the Grid Code Review Panel pursuant to
GR.20.1;
as defined in GR.20.10, and any further consultation which may be
directed by the Grid Code Review Panel pursuant to GR.20.17;
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Workgroup Alternative
Grid Code Modification
Zonal System Security
Requirements
an alternative modification to the Grid Code Modification Proposal
developed by the Workgroup under the Workgroup terms of reference
(either as a result of a Workgroup Consultation or otherwise) and which
is believed by a majority of the members of the Workgroup or by the
chairman of the Workgroup to better facilitate the Grid Code Objectives
than the Grid Code Modification Proposal or the current versionof the
Grid Code;
That generation required, within the boundary circuits defining the
System Zone, which when added to the secured transfer capability of
the boundary circuits exactly matches the Demand within the System
Zone.
A number of the terms listed above are defined in other documents, such as the Balancing and Settlement
Code and the Transmission Licence. Appendix 1 sets out the current definitions from the other documents
of those terms so used in the Grid Code and defined in other documents for ease of reference, but does not
form part of the Grid Code.
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GD.2
Construction of References
GD.2.1
In the Grid Code:
(i)
a table of contents, a Preface, a Revision section, headings, and the Appendix to this
Glossary and Definitions are inserted for convenience only and shall be ignored in
construing the Grid Code;
(ii) unless the context otherwise requires, all references to a particular paragraph, subparagraph, Appendix or Schedule shall be a reference to that paragraph, sub-paragraph
Appendix or Schedule in or to that part of the Grid Code in which the reference is made;
(iii) unless the context otherwise requires, the singular shall include the plural and vice
versa, references to any gender shall include all other genders and references to
persons shall include any individual, body corporate, corporation, joint venture, trust,
unincorporated association, organisation, firm or partnership and any other entity, in
each case whether or not having a separate legal personality;
(iv) references to the words "include" or "including" are to be construed without limitation to
the generality of the preceding words;
(v) unless there is something in the subject matter or the context which is inconsistent
therewith, any reference to an Act of Parliament or any Section of or Schedule to, or
other provision of an Act of Parliament shall be construed at the particular time, as
including a reference to any modification, extension or re-enactment thereof then in
force and to all instruments, orders and regulations then in force and made under or
deriving validity from the relevant Act of Parliament;
(vi) where the Glossary and Definitions refers to any word or term which is more
particularly defined in a part of the Grid Code, the definition in that part of the Grid Code
will prevail (unless otherwise stated) over the definition in the Glossary & Definitions in
the event of any inconsistency;
(vii) a cross-reference to another document or part of the Grid Code shall not of itself impose
any additional or further or co-existent obligation or confer any additional or further or
co-existent right in the part of the text where such cross-reference is contained;
(viii) nothing in the Grid Code is intended to or shall derogate from NGET's statutory or
licence obligations;
(ix) a "holding company" means, in relation to any person, a holding company of such
person within the meaning of section 736, 736A and 736B of the Companies Act 1985
as substituted by section 144 of the Companies Act 1989 and, if that latter section is not
in force at the Transfer Date, as if such latter section were in force at such date;
(x) a "subsidiary" means, in relation to any person, a subsidiary of such person within the
meaning of section 736, 736A and 736B of the Companies Act 1985 as substituted by
section 144 of the Companies Act 1989 and, if that latter section is not in force at the
Transfer Date, as if such latter section were in force at such date;
(xi) references to time are to London time; and
(xii) (a) Save where (b) below applies, where there is a reference to an item of data being
expressed in a whole number of MW, fractions of a MW below 0.5 shall be rounded
down to the nearest whole MW and fractions of a MW of 0.5 and above shall be
rounded up to the nearest whole MW;
(b) In the case of the definition of Registered Capacity, fractions of a MW below 0.05
shall be rounded down to one decimal place and fractions of a MW of 0.05 and above
shall be rounded up to one decimal place.
< END OF GLOSSARY & DEFINITIONS >
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PLANNING CODE
(PC)
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
PC.1 INTRODUCTION.................................................................................................................................. 2
PC.2 OBJECTIVE......................................................................................................................................... 3
PC.3 SCOPE ................................................................................................................................................ 3
PC.4 PLANNING PROCEDURES ................................................................................................................. 6
PC.5 PLANNING DATA .............................................................................................................................. 10
PC.6 PLANNING STANDARDS .................................................................................................................. 13
PC.7 PLANNING LIAISON .......................................................................................................................... 14
PC.8 OTSDUW PLANNING LIAISION ........................................................................................................ 15
APPENDIX A - PLANNING DATA REQUIREMENTS .................................................................................... 16
PART 1 - STANDARD PLANNING DATA................................................................................................. 20
PC.A.2 USER’S SYSTEM (AND OTSUA) DATA................................................................................. 20
PC.A.3 GENERATING UNIT AND DC CONVERTER DATA ............................................................... 28
PC.A.4 DEMAND AND ACTIVE ENERGY DATA ................................................................................ 34
PART 2 - DETAILED PLANNING DATA ................................................................................................... 40
PC.A.5 GENERATING UNIT, POWER PARK MODULE, DC CONVERTER AND OTSDUW PLANT
AND APPARATUS DATA ..................................................................................................................... 40
PC.A.6 USERS’ SYSTEM DATA ........................................................................................................ 55
PC.A.7 ADDITIONAL DATA FOR NEW TYPES OF POWER STATIONS, DC CONVERTER
STATIONS, OTSUA AND CONFIGURATIONS..................................................................................... 59
PART 3 – DETAILED PLANNING DATA .................................................................................................. 60
APPENDIX B - SINGLE LINE DIAGRAMS .................................................................................................... 62
APPENDIX C - TECHNICAL AND DESIGN CRITERIA .................................................................................. 65
PART 1 – SHETL’s TECHNICAL AND DESIGN CRITERIA ...................................................................... 65
PART 2 - SPT's TECHNICAL AND DESIGN CRITERIA ........................................................................... 67
APPENDIX D - DATA NOT DISCLOSED TO A RELEVANT TRANSMISSION LICENSEE ............................. 68
APPENDIX E - OFFSHORE TRANSMISSION SYSTEM AND OTSDUW PLANT AND
APPARATUS TECHNICAL AND DESIGN CRITERIA .................................................................................... 70
APPENDIX F - OTSDUW DATA AND INFORMATION AND OTSDUW NETWORK DATA AND
INFORMATION............................................................................................................................................. 71
Issue 5 Revision 15
PC
i
03 February 2015
PC.1
INTRODUCTION
PC.1.1
The Planning Code ("PC") specifies the technical and design criteria and procedures to be
applied by NGET in the planning and development of the National Electricity Transmission
System and to be taken into account by Users in the planning and development of their own
Systems. In the case of OTSUA, the PC also specifies the technical and design criteria and
procedures to be applied by the User in the planning and development of the OTSUA. It details
information to be supplied by Users to NGET, and certain information to be supplied by NGET to
Users. In Scotland and Offshore, NGET has obligations under the STC to inform Relevant
Transmission Licensees of data required for the planning of the National Electricity
Transmission System. In respect of PC data, NGET may pass on User data to a Relevant
Transmission Licensee, as detailed in PC.3.4 and PC.3.5.
PC.1.1A
Provisions of the PC which apply in relation to OTSDUW and OTSUA shall apply up to the
OTSUA Transfer Time, whereupon such provisions shall (without prejudice to any prior noncompliance) cease to apply, without prejudice to the continuing application of provisions of the
PC applying in relation to the relevant Offshore Transmission System and/or Connection Site.
PC.1.1B
As used in the PC:
(a) National Electricity Transmission System excludes OTSDUW Plant and Apparatus (prior
to the OTSUA Transfer Time) unless the context otherwise requires;
(b) and User Development includes OTSDUW unless the context otherwise requires.
PC.1.2
The Users referred to above are defined, for the purpose of the PC, in PC.3.1.
PC.1.3
Development of the National Electricity Transmission System, involving its reinforcement or
extension, will arise for a number of reasons including, but not limited to:
(a) a development on a User System already connected to the National Electricity
Transmission System;
(b) the introduction of a new Connection Site or the Modification of an existing Connection
Site between a User System and the National Electricity Transmission System;
(c) the cumulative effect of a number of such developments referred to in (a) and (b) by one or
more Users.
PC.1.4
Accordingly, the reinforcement or extension of the National Electricity Transmission System
may involve work:
(a) at a substation at a Connection Site where User's Plant and/or Apparatus is connected to
the National Electricity Transmission System (or in the case of OTSDUW, at a substation
at an Interface Point);
(b) on transmission lines or other facilities which join that Connection Site (or in the case of
OTSDUW, Interface Point) to the remainder of the National Electricity Transmission
System;
(c) on transmission lines or other facilities at or between points remote from that Connection
Site (or in the case of OTSDUW, Interface Point).
PC.1.5
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The time required for the planning and development of the National Electricity Transmission
System will depend on the type and extent of the necessary reinforcement and/or extension
work, the need or otherwise for statutory planning consent, the associated possibility of the need
for a public inquiry and the degree of complexity in undertaking the new work while maintaining
satisfactory security and quality of supply on the existing National Electricity Transmission
System.
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PC.2
OBJECTIVE
PC.2.1
The objectives of the PC are:
(a) to promote NGET/User interaction in respect of any proposed development on the User
System which may impact on the performance of the National Electricity Transmission
System or the direct connection with the National Electricity Transmission System;
(b) to provide for the supply of information to NGET from Users in order that planning and
development of the National Electricity Transmission System can be undertaken in
accordance with the relevant Licence Standards, to facilitate existing and proposed
connections, and also to provide for the supply of certain information from NGET to Users in
relation to short circuit current contributions and OTSUA; and
(c) to specify the Licence Standards which will be used in the planning and development of the
National Electricity Transmission System; and
(d) to provide for the supply of information required by NGET from Users in respect of the
following to enable NGET to carry out its duties under the Act and the Transmission
Licence:
(i)
Mothballed Generating Units; and
(ii)
capability of gas-fired Generating Units to run using alternative fuels.
NGET will use the information provided under PC.2.1(d) in providing reports to the Authority
and the Secretary of State and, where directed by the Authority or the Secretary of Sate
to do so, NGET may publish the information. Where it is known by NGET that such
information is intended for wider publication the information provided under PC.2.1(d) shall
be aggregated such that individual data items should not be identifiable.
(e) in the case of OTSUA:
(i)
to specify the minimum technical and design criteria and procedures to be applied by
Users in the planning and development of OTSUA; and thereby
(ii)
to ensure that the OTSUA can from the OTSUA Transfer Time be operated as part of
the National Electricity Transmission System; and
(iii) to provide for the arrangements and supply of information and data between NGET and
a User to ensure that the User is able to undertake OTSDUW; and
(iv) to promote NGET/User interaction and co-ordination in respect of any proposed
development on the National Electricity Transmission System or the OTSUA, which
may impact on the OTSUA or (as the case may be) the National Electricity
Transmission System.
PC.3
SCOPE
PC.3.1
The PC applies to NGET and to Users, which in the PC means:
(a) Generators;
(b) Generators undertaking OTSDUW;
(c) Network Operators;
(d) Non-Embedded Customers; and
(e) DC Converter Station owners.
The above categories of User will become bound by the PC prior to them generating, operating,
or consuming or importing/exporting, as the case may be, and references to the various
categories (or to the general category) of User should, therefore, be taken as referring to them in
that prospective role as well as to Users actually connected.
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PC.3.2
In the case of Embedded Power Stations and Embedded DC Converter Stations, unless
provided otherwise, the following provisions apply with regard to the provision of data under this
PC:
(a) each Generator shall provide the data direct to NGET in respect of (i) Embedded Large
Power Stations, (ii) Embedded Medium Power Stations subject to a Bilateral Agreement
and (iii) Embedded Small Power Stations which form part of a Cascade Hydro Scheme;
(b) each DC Converter owner shall provide the data direct to NGET in respect of Embedded
DC Converter Stations subject to a Bilateral Agreement;
(c) each Network Operator shall provide the data to NGET in respect of each Embedded
Medium Power Station not subject to a Bilateral Agreement or Embedded DC Converter
Station not subject to a Bilateral Agreement connected, or proposed to be connected
within such Network Operator’s System;
(d) although data is not normally required specifically on Embedded Small Power Stations or
on Embedded installations of direct current converters which do not form a DC Converter
Station under this PC, each Network Operator in whose System they are Embedded
should provide the data (contained in the Appendix) to NGET in respect of Embedded
Small Power Stations or Embedded installations of direct current converters which do not
form a DC Converter Station if:
PC.3.3
(i)
it falls to be supplied pursuant to the application for a CUSC Contract or in the
Statement of Readiness to be supplied in connection with a Bilateral Agreement
and/or Construction Agreement, by the Network Operator; or
(ii)
it is specifically requested by NGET in the circumstances provided for under this PC.
Certain data does not normally need to be provided in respect of certain Embedded Power
Stations or Embedded DC Converter Stations, as provided in PC.A.1.12.
In summary, Network Operators are required to supply the following data in respect of
Embedded Medium Power Stations not subject to a Bilateral Agreement or Embedded DC
Converter Stations not subject to a Bilateral Agreement connected, or is proposed to be
connected, within such Network Operator’s System:
PC.A.2.1.1
PC.A.2.2.2
PC.A.2.5.5.2
PC.A.2.5.5.7
PC.A.2.5.6
PC.A.3.1.5
PC.A.3.2.2
PC.A.3.3.1
PC.A.3.4.1
PC.A.3.4.2
PC.A.5.2.2
PC.A.5.3.2
PC.A.5.4
PC.A.5.5.1
PC.A.5.6
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For the avoidance of doubt Network Operators are required to supply the above data in respect
of Embedded Medium Power Stations not subject to a Bilateral Agreement and Embedded
DC Converter Stations not subject to a Bilateral Agreement which are located Offshore and
which are connected or proposed to be connected within such Network Operator’s System.
This is because Embedded Medium Power Stations not subject to a Bilateral Agreement and
Embedded DC Converter Stations not subject to a Bilateral Agreement are treated as
Onshore Generators or Onshore DC Converter Station owners connected to an Onshore
User System Entry Point.
PC.3.4
NGET may provide to the Relevant Transmission Licensees any data which has been
submitted to NGET by any Users pursuant to the following paragraphs of the PC. For the
avoidance of doubt, NGET will not provide to the Relevant Transmission Licensees, the types
of data specified in Appendix D. The Relevant Transmission Licensees’ use of such data is
detailed in the STC.
PC.A.2.2
PC.A.2.5
PC.A.3.1
PC.A.3.2.1
PC.A.3.2.2
PC.A.3.3
PC.A.3.4
PC.A.4
PC.A.5.1
PC.A.5.2
PC.A.5.3.1
PC.A.5.3.2
PC.A.5.4.1
PC.A.5.4.2
PC.A.5.4.3.1
PC.A.5.4.3.2
PC.A.5.4.3.3
PC.A.5.4.3.4
PC.A.7
(and in addition in respect of the data submitted in respect of the OTSUA)
PC.A.2.2
PC.A.2.3
PC.A.2.4
PC.A.2.5
PC.A.3.2.2
PC.A.3.3.1(d)
PC.A.4
PC.A.5.4.3.1
PC.A.5.4.3.2
PC.A.6.2
PC.A.6.3
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PC.A.6.4
PC.A.6.5
PC.A.6.6
PC.A.7
PC.3.5
In addition to the provisions of PC.3.4 NGET may provide to the Relevant Transmission
Licensees any data which has been submitted to NGET by any Users in respect of Relevant
Units pursuant to the following paragraphs of the PC.
PC.A.2.3
PC.A.2.4
PC.A.5.5
PC.A.5.7
PC.A.6.2
PC.A.6.3
PC.A.6.4
PC.A.6.5
PC.A.6.6
PC.3.6
In the case of Offshore Embedded Power Stations connected to an Offshore User System
which directly connects to an Offshore Transmission System, any additional data requirements
in respect of such Offshore Embedded Power Stations may be specified in the relevant
Bilateral Agreement with the Network Operator or in any Bilateral Agreement between NGET
and such Offshore Embedded Power Station.
PC.3.7
In the case of a Generator undertaking OTSDUW connecting to an Onshore Network
Operator’s System, any additional requirements in respect of such OTSDUW Plant and
Apparatus will be specified in the relevant Bilateral Agreement with the Generator. For the
avoidance of doubt, requirements applicable to Generators undertaking OTSDUW and
connecting to a Network Operator’s User System, shall be consistent with those applicable
requirements of Generators undertaking OTSDUW and connecting to a Transmission Interface
Point.
PC.4
PLANNING PROCEDURES
PC.4.1
Pursuant to Condition C11 of NGET’s Transmission Licence, the means by which Users and
proposed Users of the National Electricity Transmission System are able to assess
opportunities for connecting to, and using, the National Electricity Transmission System
comprise two distinct parts, namely:
(a) a statement, prepared by NGET under its Transmission Licence, showing for each of the
seven succeeding Financial Years, the opportunities available for connecting to and using
the National Electricity Transmission System and indicating those parts of the National
Electricity Transmission System most suited to new connections and transport of further
quantities of electricity (the "Seven Year Statement"); and
(b) an offer, in accordance with its Transmission Licence, by NGET to enter into a CUSC
Contract. A Bilateral Agreement is to be entered into for every Connection Site (and for
certain Embedded Power Stations and Embedded DC Converter Stations) within the first
two of the following categories and the existing Bilateral Agreement may be required to be
varied in the case of the third category:
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(i)
existing Connection Sites (and for certain Embedded Power Stations) as at the
Transfer Date;
(ii)
new Connection Sites (and for certain Embedded Power Stations and for Embedded
DC Converter Stations) with effect from the Transfer Date;
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(iii) a Modification at a Connection Site (or in relation to the connection of certain
Embedded Power Stations and for Embedded DC Converter Stations whether or not
the subject of a Bilateral Agreement) (whether such Connection Site or connection
exists on the Transfer Date or is new thereafter) with effect from the Transfer Date.
In this PC, unless the context otherwise requires, "connection" means any of these 3
categories.
PC.4.2
Introduction to Data
User Data
PC.4.2.1
Under the PC, two types of data to be supplied by Users are called for:
(a) Standard Planning Data; and
(b) Detailed Planning Data,
as more particularly provided in PC.A.1.4.
PC.4.2.2
The PC recognises that these two types of data, namely Standard Planning Data and Detailed
Planning Data, are considered at three different levels:
(a) Preliminary Project Planning Data;
(b) Committed Project Planning Data; and
(c) Connected Planning Data,
as more particularly provided in PC.5
PC.4.2.3
Connected Planning Data is itself divided into:
(a) Forecast Data;
(b) Registered Data; and
(c) Estimated Registered Data,
as more particularly provided in PC.5.5
PC.4.2.4
Clearly, an existing User proposing a new Connection Site (or Embedded Power Station or
Embedded DC Converter Station in the circumstances outlined in PC.4.1) will need to supply
data both in an application for a Bilateral Agreement and under the PC in relation to that
proposed new Connection Site (or Embedded Power Station or Embedded DC Converter
Station in the circumstances outlined in PC.4.1) and that will be treated as Preliminary Project
Planning Data or Committed Project Planning Data (as the case may be), but the data it
supplies under the PC relating to its existing Connection Sites will be treated as Connected
Planning Data.
Network Data
PC.4.2.5
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In addition, there is Network Data supplied by NGET in relation to short circuit current
contributions and in relation to OTSUA.
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PC.4.3
Data Provision
PC.4.3.1
Seven Year Statement
To enable the Seven Year Statement to be prepared, each User is required to submit to NGET
(subject to the provisions relating to Embedded Power Stations and Embedded DC Converter
Stations in PC.3.2) both the Standard Planning Data and the Detailed Planning Data as listed
in parts l and 2 of the Appendix. This data should be submitted in calendar week 24 of each year
(although Network Operators may delay the submission of data (other than that to be submitted
pursuant to PC.3.2(c) and PC.3.2(d)) until calendar week 28) and should cover each of the seven
succeeding Financial Years (and in certain instances, the current year). Where, from the date of
one submission to another, there is no change in the data (or in some of the data) to be
submitted, instead of re-submitting the data, a User may submit a written statement that there
has been no change from the data (or in some of the data) submitted the previous time. In
addition, NGET will also use the Transmission Entry Capacity and Connection Entry Capacity
data from the CUSC Contract, and any data submitted by Network Operators in relation to an
Embedded Medium Power Station not subject to a Bilateral Agreement or Embedded DC
Converter Station not subject to a Bilateral Agreement, in the preparation of the Seven Year
Statement and to that extent the data will not be treated as confidential.
PC.4.3.2
Network Data
To enable Users to model the National Electricity Transmission System in relation to short
circuit current contributions, NGET is required to submit to Users the Network Data as listed in
Part 3 of the Appendix. The data will be submitted in week 42 of each year and will cover that
Financial Year.
PC.4.3.3
To enable Users to model the National Electricity Transmission System in relation to OTSUA,
NGET is required to submit to Users the Network Data as listed in Part 3 of Appendix A and
Appendix F. NGET shall provide the Network Data with the offer of a CUSC Contract in the case
of the data in PC F2.1 and otherwise in accordance with the OTSDUW Development and Data
Timetable.
PC.4.4
Offer of Terms for Connection
PC.4.4.1
CUSC Contract – Data Requirements/Offer Timing
The completed application form for a CUSC Contract to be submitted by a User when making an
application for a CUSC Contract will include:
(a) a description of the Plant and/or Apparatus (excluding OTSDUW Plant and Apparatus) to
be connected to the National Electricity Transmission System or of the Modification
relating to the User's Plant and/or Apparatus (and prior to the OTSUA Transfer Time, any
OTSUA) already connected to the National Electricity Transmission System or, as the
case may be, of the proposed new connection or Modification to the connection within the
User System of the User, each of which shall be termed a "User Development" in the PC;
(b) the relevant Standard Planning Data as listed in Part 1 of the Appendix (except in respect
of any OTSUA); and
(c) the desired Completion Date of the proposed User Development.
(d) the desired Connection Entry Capacity and Transmission Entry Capacity.
The completed application form for a CUSC Contract will be sent to NGET as more particularly
provided in the application form.
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PC.4.4.2
Any offer of a CUSC Contract will provide that it must be accepted by the applicant User within
the period stated in the offer, after which the offer automatically lapses. Except as provided in the
CUSC Contract, acceptance of the offer renders the National Electricity Transmission System
works relating to that User Development, reflected in the offer, committed and binds both parties
to the terms of the offer. The User shall then provide the Detailed Planning Data as listed in Part
2 of the Appendix (and in the case of OTSUA the Standard Planning Data as listed in Part 1 of
Appendix A within the timeline provided in PC.A.1.4). In respect of DPD I this shall generally be
provided within 28 days (or such shorter period as NGET may determine, or such longer period
as NGET may agree, in any particular case) of acceptance of the offer and in respect of DPD II
this shall generally be provided at least two years (or such longer period as NGET may
determine, or such shorter period as NGET may agree, in any particular case or in the case of
OTSUA such shorter period as NGET shall require) prior to the Completion Date of the User
Development.
PC.4.4.3
Embedded Development Agreement - Data Requirements
The Network Operator shall submit the following data in relation to an Embedded Medium
Power Station not subject to, or proposed to be subject to, a Bilateral Agreement or Embedded
DC Converter Station not subject to, or proposed to be subject to, a Bilateral Agreement as
soon as reasonably practicable after receipt of an application from an Embedded Person to
connect to its System:
(a) details of the proposed new connection or variation (having a similar effect on the Network
Operator’s System as a Modification would have on the National Electricity
Transmission System) to the connection within the Network Operator’s System, each of
which shall be termed an “Embedded Development” in the PC (where a User
Development has an impact on the Network Operator’s System details shall be supplied
in accordance with PC.4.4 and PC.4.5);
(b) the relevant Standard Planning Data as listed in Part 1 of the Appendix;
(c) the proposed completion date (having a similar meaning in relation to the Network
Operator’s System as Completion Date would have in relation to the National Electricity
Transmission System) of the Embedded Development; and
(d) upon the request of NGET, the relevant Detailed Planning Data as listed in Part 2 of the
Appendix.
PC.4.4.4
The Network Operator shall provide the Detailed Planning Data as listed in Part 2 of the
Appendix. In respect of DPD I this shall generally be provided within 28 days (or such shorter
period as NGET may determine, or such longer period as NGET may agree, in any particular
case) of entry into the Embedded Development Agreement and in respect to DPD II this shall
generally be provided at least two years (or such longer period as NGET may determine, or such
shorter period as NGET may agree, in any particular case) prior to the Completion Date of the
Embedded Development.
PC.4.5
Complex Connections
PC.4.5.1
The magnitude and complexity of any National Electricity Transmission System extension or
reinforcement will vary according to the nature, location and timing of the proposed User
Development which is the subject of the application and it may, in the event, be necessary for
NGET to carry out additional more extensive system studies to evaluate more fully the impact of
the proposed User Development on the National Electricity Transmission System. Where
NGET judges that such additional more detailed studies are necessary the offer may indicate the
areas that require more detailed analysis and before such additional studies are required, the
User shall indicate whether it wishes NGET to undertake the work necessary to proceed to make
a revised offer within the 3 month period normally allowed or, where relevant, the timescale
consented to by the Authority.
PC.4.5.2
To enable NGET to carry out any of the above mentioned necessary detailed system studies, the
User may, at the request of NGET, be required to provide some or all of the Detailed Planning
Data listed in part 2 of the Appendix in advance of the normal timescale referred in PC.4.4.2
provided that NGET can reasonably demonstrate that it is relevant and necessary.
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PC.4.5.3
To enable NGET to carry out any necessary detailed system studies, the relevant Network
Operator may, at the request of NGET, be required to provide some or all of the Detailed
Planning Data listed in Part 2 of the Appendix in advance of the normal timescale referred in
PC.4.4.4 provided that NGET can reasonably demonstrate that it is relevant and necessary.
PC.5
PLANNING DATA
PC.5.1
As far as the PC is concerned, there are three relevant levels of data in relation to Users. These
levels, which relate to levels of confidentiality, commitment and validation, are described in the
following paragraphs.
Preliminary Project Planning Data
PC.5.2
At the time the User applies for a CUSC Contract but before an offer is made and accepted by
the applicant User, the data relating to the proposed User Development will be considered as
Preliminary Project Planning Data. Data relating to an Embedded Development provided by a
Network Operator in accordance with PC.4.4.3, and PC.4.4.4 if requested, will be considered as
Preliminary Project Planning Data. All such data will be treated as confidential within the scope
of the provisions relating to confidentiality in the CUSC.
PC.5.3
Preliminary Project Planning Data will normally only contain the Standard Planning Data
unless the Detailed Planning Data is required in advance of the normal timescale to enable
NGET to carry out additional detailed system studies as described in PC.4.5.
Committed Project Planning Data
PC.5.4
Once the offer for a CUSC Contract is accepted, the data relating to the User Development
already submitted as Preliminary Project Planning Data, and subsequent data required by
NGET under this PC, will become Committed Project Planning Data. Once an Embedded
Person has entered into an Embedded Development Agreement, as notified to NGET by the
Network Operator, the data relating to the Embedded Development already submitted as
Preliminary Project Planning Data, and subsequent data required by NGET under the PC, will
become Committed Project Planning Data. Such data, together with Connection Entry
Capacity and Transmission Entry Capacity data from the CUSC Contract and other data held
by NGET relating to the National Electricity Transmission System will form the background
against which new applications by any User will be considered and against which planning of the
National Electricity Transmission System will be undertaken. Accordingly, Committed Project
Planning Data, Connection Entry Capacity and Transmission Entry Capacity data will not be
treated as confidential to the extent that NGET:
(a) is obliged to use it in the preparation of the Seven Year Statement and in any further
information given pursuant to the Seven Year Statement;
(b) is obliged to use it when considering and/or advising on applications (or possible
applications) of other Users (including making use of it by giving data from it, both orally and
in writing, to other Users making an application (or considering or discussing a possible
application) which is, in NGET's view, relevant to that other application or possible
application);
(c) is obliged to use it for operational planning purposes;
(d) is obliged under the terms of an Interconnection Agreement to pass it on as part of system
information on the Total System;
(e) is obliged to disclose it under the STC;
(f)
is obliged to use and disclose it in the preparation of the Offshore Development
Information Statement;
(g) is obliged to use it in order to carry out its EMR Functions or is obliged to disclose it under
an EMR Document.
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To reflect different types of data, Preliminary Project Planning Data and Committed Project
Planning Data are themselves divided into:
(a) those items of Standard Planning Data and Detailed Planning Data which will always be
forecast, known as Forecast Data; and
(b) those items of Standard Planning Data and Detailed Planning Data which relate to Plant
and/or Apparatus which upon connection will become Registered Data, but which prior to
connection, for the seven succeeding Financial Years, will be an estimate of what is
expected, known as Estimated Registered Data.
Connected Planning Data
PC.5.5
The PC requires that, at the time that a Statement of Readiness is submitted under the Bilateral
Agreement and/or Construction Agreement, any estimated values assumed for planning
purposes are confirmed or, where practical, replaced by validated actual values and by updated
estimates for the future and by updated forecasts for forecast data items such as Demand. In
the case of an Embedded Development the relevant Network Operator will update any
estimated values assumed for planning purposes with validated actual values as soon as
reasonably practicable after energisation. This data is then termed Connected Planning Data.
To reflect the three types of data referred to above, Connected Planning Data is itself divided
into:
(a) those items of Standard Planning Data and Detailed Planning Data which will always be
forecast data, known as Forecast Data; and
(b) those items of Standard Planning Data and Detailed Planning Data which upon
connection become fixed (subject to any subsequent changes), known as Registered Data;
and
(c) those items of Standard Planning Data and Detailed Planning Data which for the purposes
of the Plant and/or Apparatus concerned as at the date of submission are Registered Data
but which for the seven succeeding Financial Years will be an estimate of what is expected,
known as Estimated Registered Data,
as more particularly provided in the Appendix.
PC.5.6
Connected Planning Data, together with Connection Entry Capacity and Transmission Entry
Capacity data from the CUSC Contract, and other data held by NGET relating to the National
Electricity Transmission System, will form the background against which new applications by
any User will be considered and against which planning of the National Electricity
Transmission System will be undertaken. Accordingly, Connected Planning Data, Connection
Entry Capacity and Transmission Entry Capacity data will not be treated as confidential to the
extent that NGET:
(a) is obliged to use it in the preparation of the Seven Year Statement and in any further
information given pursuant to the Seven Year Statement;
(b) is obliged to use it when considering and/or advising on applications (or possible
applications) of other Users (including making use of it by giving data from it, both orally and
in writing, to other Users making an application (or considering or discussing a possible
application) which is, in NGET's view, relevant to that other application or possible
application);
(c) is obliged to use it for operational planning purposes;
(d) is obliged under the terms of an Interconnection Agreement to pass it on as part of system
information on the Total System.
(e) is obliged to disclose it under the STC;
(f)
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is obliged to use it in order to carry out its EMR Functions or is obliged to disclose it under
an EMR Document.
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PC.5.7
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Committed Project Planning Data and Connected Planning Data will each contain both
Standard Planning Data and Detailed Planning Data.
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PC.6
PLANNING STANDARDS
PC.6.1
NGET shall apply the Licence Standards relevant to planning and development, in the planning
and development of its Transmission System. NGET shall procure that each Relevant
Transmission Licensee shall apply the Licence Standards relevant to planning and
development, in the planning and development of the Transmission System of each Relevant
Transmission Licensee and that a User shall apply the Licence Standards relevant to planning
and development, in the planning and development of the OTSUA.
PC.6.2
In relation to Scotland, Appendix C lists the technical and design criteria applied in the planning
and development of each Relevant Transmission Licensee's Transmission System. The
criteria are subject to review in accordance with each Relevant Transmission Licensee’s
Transmission Licence conditions. Copies of these documents are available from NGET on
request. NGET will charge an amount sufficient to recover its reasonable costs incurred in
providing this service.
PC.6.3
In relation to Offshore, Appendix E lists the technical and design criteria applied in the planning
and development of each Offshore Transmission System. The criteria are subject to review in
accordance with each Offshore Transmission Licensee’s Transmission Licence conditions.
Copies of these documents are available from NGET on request. NGET will charge an amount
sufficient to recover its reasonable costs incurred in providing this service.
PC.6.4
In planning and developing the OTSUA, the User shall comply with (and shall ensure that (as at
the OTSUA Transfer Time) the OTSUA comply with):
(a) the Licence Standards; and
(b) the technical and design criteria in Appendix E.
PC.6.5
In addition the User shall, in the planning and development of the OTSUA, to the extent it is
reasonable and practicable to do so, take into account the reasonable requests of NGET (in the
context of its obligation to develop an efficient, co-ordinated and economical system) relating to
the planning and development of the National Electricity Transmission System.
PC.6.6
In planning and developing the OTSUA the User shall take into account the Network Data
provided to it by NGET under Part 3 of Appendix A and Appendix F, and act on the basis that the
Plant and Apparatus of other Users complies with:
(a) the minimum technical design and operational criteria and performance requirements set out
in CC.6.1, CC.6.2, CC.6.3 and CC.6.4; or
(b) such other criteria or requirements as NGET may from time to time notify the User are
applicable to specified Plant and Apparatus pursuant to PC.6.7.
PC.6.7
Where the OTSUA are likely to be materially affected by the design or operation of another
User's Plant and Apparatus and NGET:
(a) becomes aware that such other User has or is likely to apply for a derogation under the Grid
Code;
(b) is itself applying for a derogation under the Grid Code in relation to the Connection Site on
which such other User's Plant and Apparatus is located or to which it otherwise relates; or
(c) is otherwise notified by such other User that specified Plant or Apparatus is normally
capable of operating at levels better than those set out in CC.6.1, CC.6.2, CC.6.3 and
CC.6.4,
NGET shall notify the User.
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PC.7
PLANNING LIAISON
PC.7.1
This PC.7 applies to NGET and Users, which in PC.7 means
(a) Network Operators
(b) Non-Embedded Customers
PC.7.2
As described in PC.2.1 (b) an objective of the PC is to provide for the supply of information to
NGET by Users in order that planning and development of the National Electricity
Transmission System can be undertaken in accordance with the relevant Licence Standards.
PC.7.3
Grid Code amendment B/07 (“Amendment B/07”) implemented changes to the Grid Code which
included amendments to the datasets provided by both NGET and Users to inform the planning
and development of the National Electricity Transmission System. The Authority has
determined that these changes are to have a phased implementation. Consequently the
provisions of Appendix A to the PC include specific years (ranging from 2009 to 2011) with effect
from which certain of the specific additional obligations brought about by Amendment B/07 on
NGET and Users are to take effect. Where specific provisions of paragraphs PC.A.4.1.4,
PC.A.4.2.2 and PC.A.4.3.1 make reference to a year, then the obligation on NGET and the Users
shall be required to be met by the relevant calendar week (as specified within such provision) in
such year.
In addition to the phased implementation of aspects of Amendment B/07, Users must discuss
and agree with NGET by no later than 31 March 2009 a more detailed implementation
programme to facilitate the implementation of Grid Code amendment B/07.
It shall also be noted by NGET and Users that the dates set out in PC.A.4 are intended to be
minimum requirements and are not intended to restrict a User and NGET from the earlier
fulfilment of the new requirements prior to the specified years. Where NGET and a User wish to
follow the new requirements from earlier dates than those specified, this will be set out in the
more detailed implementation programme agreed between NGET and the User.
The following provisions of PC.7 shall only apply with effect from 1 January 2011.
PC.7.4
Following the submission of data by a User in or after week 24 of each year NGET will provide
information to Users by calendar week 6 of the following year regarding the results of any
relevant assessment that has been made by NGET based upon such data submissions to verify
whether Connection Points are compliant with the relevant Licence Standards.
PC.7.5
Where the result of any assessment identifies possible future non-compliance with the relevant
Licence Standards NGET shall notify the relevant User(s) of this fact as soon as reasonably
practicable and shall agree with Users any opportunity to resubmit data to allow for a
reassessment in accordance with PC.7.6.
PC.7.6
Following any notification by NGET to a User pursuant to PC.7.5 and following any further
discussions held between the User and NGET:
(i)
NGET and the User may agree revisions to the Access Periods for relevant Transmission
Interface Circuits, such revisions shall not however permit an Access Period to be less
than 4 continuous weeks in duration or to occur other than between calendar weeks 10 and
43 (inclusive); and/or,
(ii)
The User shall as soon as reasonably practicable
(a) submit further relevant data to NGET that is to NGET’s reasonable satisfaction; and/or,
(b) modify data previously submitted pursuant to this PC, such modified data to be to
NGET’s reasonable satisfaction; and/or
(c)
notify NGET that it is the intention of the User to leave the data as originally submitted
to NGET to stand as its submission.
PC.7.7
Where an Access Period is amended pursuant to PC.7.6 (i) NGET shall notify The Authority
that it has been necessary to do so.
PC.7.8
When it is agreed that any resubmission of data is unlikely to confirm future compliance with the
relevant Licence Standards the Modification process in the CUSC may apply.
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PC.7.9
A User may at any time, in writing, request further specified National Electricity Transmission
System network data in order to provide NGET with viable User network data (as required under
this PC). Upon receipt of such request NGET shall consider, and where appropriate provide such
National Electricity Transmission System network data to the User as soon as reasonably
practicable following the request.
PC.8
OTSDUW PLANNING LIAISON
PC.8.1
This PC.8 applies to NGET and Users, which in PC.8 means Users undertaking OTSDUW
PC.8.2
As described in PC.2.1 (e) an objective of the PC is to provide for the supply of information
between NGET and a User undertaking OTSDUW in order that planning and development of the
National Electricity Transmission System can beco-ordinated.
PC.8.3
Where the OTSUA also require works to be undertaken by NGET and/or any Relevant
Transmission Licensee on its Transmission System NGET and the User shall throughout the
construction and commissioning of such works:
(a) co-operate and assist each other in the development of co-ordinated construction
programmes or any other planning or, in the case of NGET, analysis it undertakes in respect
of the works; and
(b) provide to each other all information relating to its own works (and in the case of NGET the
works on other Transmission Systems) reasonably necessary to assist each other in the
performance of that other's part of the works, and shall use all reasonable endeavours to coordinate and integrate their respective part of the works; and
the User shall plan and develop the OTSUA, taking into account to the extent that it is
reasonable and practicable to do so the reasonable requests of NGET relating to the planning
and development of the National Electricity Transmission System.
PC.8.4
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Where NGET becomes aware that changes made to the investment plans of NGET and any
Relevant Transmission Licensee may have a material effect on the OTSUA, NGET shall notify
the User and provide the User with the necessary information about the relevant Transmission
Systems sufficient for the User to assess the impact on the OTSUA.
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APPENDIX A - PLANNING DATA REQUIREMENTS
PC.A.1
INTRODUCTION
PC.A.1.1
The Appendix specifies data requirements to be submitted to NGET by Users, and in certain
circumstances to Users by NGET.
PC.A.1.2
Submissions by Users
(a) Planning data submissions by Users shall be:
(i)
with respect to each of the seven succeeding Financial Years (other than in the case
of Registered Data which will reflect the current position and data relating to Demand
forecasts which relates also to the current year);
(ii)
provided by Users in connection with a CUSC Contract (PC.4.1, PC.4.4 and PC.4.5
refer);
(iii) provided by Users on a routine annual basis in calendar week 24 of each year to
maintain an up-to-date data bank (although Network Operators may delay the
submission of data (other than that to be submitted pursuant to PC.3.2(c) and
PC.3.2(d)) until calendar week 28). Where from the date of one annual submission to
another there is no change in the data (or in some of the data) to be submitted, instead
of re-submitting the data, a User may submit a written statement that there has been
no change from the data (or some of the data) submitted the previous time; and
(iv) provided by Network Operators in connection with Embedded Development (PC.4.4
refers).
(b) Where there is any change (or anticipated change) in Committed Project Planning Data or
a significant change in Connected Planning Data in the category of Forecast Data or any
change (or anticipated change) in Connected Planning Data in the categories of
Registered Data or Estimated Registered Data supplied to NGET under the PC,
notwithstanding that the change may subsequently be notified to NGET under the PC as
part of the routine annual update of data (or that the change may be a Modification under
the CUSC), the User shall, subject to PC.A.3.2.3 and PC.A.3.2.4, notify NGET in writing
without delay.
(c) The notification of the change will be in the form required under this PC in relation to the
supply of that data and will also contain the following information:
(i)
the time and date at which the change became, or is expected to become, effective;
(ii)
if the change is only temporary, an estimate of the time and date at which the data will
revert to the previous registered form.
(d) The routine annual update of data, referred to in (a)(iii) above, need not be submitted in
respect of Small Power Stations or Embedded installations of direct current converters
which do not form a DC Converter Station (except as provided in PC.3.2.(c)), or unless
specifically requested by NGET, or unless otherwise specifically provided.
PC.A.1.3
Submissions by NGET
Network Data release by NGET shall be:
(a) with respect to the current Financial Year;
(b) provided by NGET on a routine annual basis in calendar week 42 of each year. Where from
the date of one annual submission to another there is no change in the data (or in some of
the data) to be released, instead of repeating the data, NGET may release a written
statement that there has been no change from the data (or some of the data) released the
previous time.
The three parts of the Appendix
PC.A.1.4
The data requirements listed in this Appendix are subdivided into the following four parts:
(a) Standard Planning Data
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This data (as listed in Part 1 of the Appendix) is first to be provided by a User at the time of
an application for a CUSC Contract or in accordance with PC.4.4.3. It comprises data
which is expected normally to be sufficient for NGET to investigate the impact on the
National Electricity Transmission System of any User Development or Embedded
Development associated with an application by the User for a CUSC Contract. Users
should note that the term Standard Planning Data also includes the information referred to
in PC.4.4.1.(a) and PC.4.4.3.(a). In the case of OTSUA, this data is first to be provided by a
User in accordance with the time line in Appendix F.
(b) Detailed Planning Data
This data (as listed in Part 2 of the Appendix) includes both DPD I and DPD II and is to be
provided in accordance with PC.4.4.2 and PC.4.4.4. It comprises additional, more detailed,
data not normally expected to be required by NGET to investigate the impact on the
National Electricity Transmission System of any User Development associated with an
application by the User for a CUSC Contract or Embedded Development Agreement.
Users and Network Operators in respect of Embedded Developments should note that
the term Detailed Planning Data also includes Operation Diagrams and Site Common
Drawings produced in accordance with the CC.
The User may, however, be required by NGET to provide the Detailed Planning Data in
advance of the normal timescale before NGET can make an offer for a CUSC Contract, as
explained in PC.4.5.
(c) Network Data
The data requirements for NGET in this Appendix are in Part 3.
(d) Offshore Transmission System (OTSDUW) Data
Generators who are undertaking OTSDUW are required to submit data in accordance with
Appendix A as summarised in Schedule 18 of the Data Registration Code.
Forecast Data, Registered Data and Estimated Registered Data
PC.A.1.5
As explained in PC.5.4 and PC.5.5, Planning Data is divided into:
(i)
those items of Standard Planning Data and Detailed Planning Data known as Forecast
Data; and
(ii)
those items of Standard Planning Data and Detailed Planning Data known as Registered
Data; and
(iii) those items of Standard Planning Data and Detailed Planning Data known as Estimated
Registered Data.
PC.A.1.6
The following paragraphs in this Appendix relate to Forecast Data:
3.2.2(b), (h), (i) and (j)
4.2.1
4.3.1
4.3.2
4.3.3
4.3.4
4.3.5
4.5
4.7.1
5.2.1
5.2.2
5.6.1
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PC.A.1.7
The following paragraphs in this Appendix relate to Registered Data and Estimated Registered
Data:
2.2.1
2.2.4
2.2.5
2.2.6
2.3.1
2.4.1
2.4.2
3.2.2(a), (c), (d), (e), (f), (g), (i)(part) and (j)
3.4.1
3.4.2
4.2.3
4.5(a)(i), (a)(iii), (b)(i) and (b)(iii)
4.6
5.3.2
5.4
5.4.2
5.4.3
5.5
5.6.3
6.2
6.3
PC.A.1.8
The data supplied under PC.A.3.3.1, although in the nature of Registered Data, is only supplied
either upon application for a CUSC Contract, or in accordance with PC.4.4.3, and therefore does
not fall to be Registered Data, but is Estimated Registered Data.
PC.A.1.9
Forecast Data must contain the User's best forecast of the data being forecast, acting as a
reasonable and prudent User in all the circumstances.
PC.A.1.10
Registered Data must contain validated actual values, parameters or other information (as the
case may be) which replace the estimated values, parameters or other information (as the case
may be) which were given in relation to those data items when they were Preliminary Project
Planning Data and Committed Project Planning Data, or in the case of changes, which replace
earlier actual values, parameters or other information (as the case may be). Until amended
pursuant to the Grid Code, these actual values, parameters or other information (as the case
may be) will be the basis upon which the National Electricity Transmission System is planned,
designed, built and operated in accordance with, amongst other things, the Transmission
Licences, the STC and the Grid Code, and on which NGET therefore relies. In following the
processes set out in the BC, NGET will use the data which has been supplied to it under the BC
and the data supplied under OC2 in relation to Gensets, but the provision of such data will not
alter the data supplied by Users under the PC, which may only be amended as provided in the
PC.
PC.A.1.11
Estimated Registered Data must contain the User's best estimate of the values, parameters or
other information (as the case may be), acting as a reasonable and prudent User in all the
circumstances.
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PC.A.1.12
Certain data does not need to be supplied in relation to Embedded Power Stations or
Embedded DC Converter Stations where these are connected at a voltage level below the
voltage level directly connected to the National Electricity Transmission System except in
connection with a CUSC Contract, or unless specifically requested by NGET.
PC.A.1.13
In the case of OTSUA, Schedule 18 of the Data Registration Code shall be construed in such a
manner as to achieve the intent of such provisions by reference to the OTSUA and the Interface
Point and all Connection Points.
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PART 1 - STANDARD PLANNING DATA
PC.A.2
USER'S SYSTEM (AND OTSUA) DATA
PC.A.2.1
Introduction
PC.A.2.1.1
Each User, whether connected directly via an existing Connection Point to the National
Electricity Transmission System, or seeking such a direct connection, or providing terms for
connection of an Offshore Transmission System to its User System to NGET, shall provide
NGET with data on its User System (and any OTSUA) which relates to the Connection Site
(and in the case of OTSUA, the Interface Point) and/or which may have a system effect on the
performance of the National Electricity Transmission System. Such data, current and forecast,
is specified in PC.A.2.2 to PC.A.2.5. In addition each Generator in respect of its Embedded
Large Power Stations and its Embedded Medium Power Stations subject to a Bilateral
Agreement and each Network Operator in respect of Embedded Medium Power Stations
within its System not subject to a Bilateral Agreement connected to the Subtransmission
System, shall provide NGET with fault infeed data as specified in PC.A.2.5.5 and each DC
Converter owner with Embedded DC Converter Stations subject to a Bilateral Agreement, or
Network Operator in the case of Embedded DC Converter Stations not subject to a Bilateral
Agreement, connected to the Subtransmission System shall provide NGET with fault infeed
data as specified in PC.A.2.5.6.
PC.A.2.1.2
Each User must reflect the system effect at the Connection Site(s) of any third party Embedded
within its User System whether existing or proposed.
PC.A.2.1.3
Although not itemised here, each User with an existing or proposed Embedded Small Power
Station, Embedded Medium Power Station or Embedded DC Converter Station with a
Registered Capacity of less than 100MW or an Embedded installation of direct current
converters which does not form a DC Converter Station in its User System may, at NGET's
reasonable discretion, be required to provide additional details relating to the User's System
between the Connection Site and the existing or proposed Embedded Small Power Station,
Embedded Medium Power Station or Embedded DC Converter Station or Embedded
installation of direct current converters which does not form a DC Converter Station.
PC.A.2.1.4
At NGET’s reasonable request, additional data on the User’s System (or OTSUA) will need to be
supplied. Some of the possible reasons for such a request, and the data required, are given in
PC.A.6.2, PC.A.6.4, PC.A.6.5 and PC.A.6.6.
PC.A.2.2
User's System (and OTSUA) Layout
PC.A.2.2.1
Each User shall provide a Single Line Diagram, depicting both its existing and proposed
arrangement(s) of load current carrying Apparatus relating to both existing and proposed
Connection Points (including in the case of OTSUA, Interface Points).
PC.A.2.2.2
The Single Line Diagram (three examples are shown in Appendix B) must include all parts of the
User System operating at Supergrid Voltage throughout Great Britain and, in Scotland and
Offshore, also all parts of the User System operating at 132kV, and those parts of its
Subtransmission System at any Transmission Site. In the case of OTSDUW, the Single Line
Diagram must also include the OTSUA. In addition, the Single Line Diagram must include all
parts of the User’s Subtransmission System (and any OTSUA) throughout Great Britain
operating at a voltage greater than 50kV, and, in Scotland and Offshore, also all parts of the
User’s Subtransmission System (and any OTSUA) operating at a voltage greater than 30kV,
which, under either intact network or Planned Outage conditions:(a) normally interconnects separate Connection Points, or busbars at a Connection Point
which are normally run in separate sections; or
(b) connects Embedded Large Power Stations, or Embedded Medium Power Stations, or
Embedded DC Converter Stations or Offshore Transmission Systems connected to the
User’s Subtransmission System, to a Connection Point or Interface Point.
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At the User’s discretion, the Single Line Diagram can also contain additional details of the
User’s Subtransmission System (and any OTSUA) not already included above, and also
details of the transformers connecting the User’s Subtransmission System to a lower
voltage. With NGET’s agreement, the Single Line Diagram can also contain information
about the User’s System (and any OTSUA) at a voltage below the voltage of the
Subtransmission System.
The Single Line Diagram for a Power Park Module must include all parts of the System
connecting generating equipment to the Grid Entry Point (or User System Entry Point if
Embedded). As an alternative the User may choose to submit a Single Line Diagram with
the equipment between the equivalent Power Park Unit and the Common Collection
Busbar reduced to an electrically equivalent network. The format for a Single Line
Diagram for a Power Park Module electrically equivalent system is shown in Appendix B.
The Single Line Diagram must include the points at which Demand data (provided under
PC.A.4.3.4 and PC.A.4.3.5, or in the case of Generators, PC.A.5.) and fault infeed data
(provided under PC.A.2.5) are supplied.
PC.A.2.2.3
The above mentioned Single Line Diagram shall include:
(a) electrical circuitry (ie. overhead lines, identifying which circuits are on the same towers,
underground cables, power transformers, reactive compensation equipment and similar
equipment); and
(b) substation names (in full or abbreviated form) with operating voltages.
In addition, for all load current carrying Apparatus operating at Supergrid Voltage throughout
Great Britain and, in Scotland and Offshore, also at 132kV, (and any OTSUA) the Single Line
Diagram shall include:(a) circuit breakers
(b) phasing arrangements.
PC.A.2.2.3.1
For the avoidance of doubt, the Single Line Diagram to be supplied is in addition to the
Operation Diagram supplied pursuant to CC.7.4.
PC.A.2.2.4
For each circuit shown on the Single Line Diagram provided under PC.A.2.2.1, each User shall
provide the following details relating to that part of its User System and OTSUA:
Circuit Parameters:
Rated voltage (kV)
Operating voltage (kV)
Positive phase sequence reactance
Positive phase sequence resistance
Positive phase sequence susceptance
Zero phase sequence reactance (both self and mutual)
Zero phase sequence resistance (both self and mutual)
Zero phase sequence susceptance (both self and mutual)
In the case of a Single Line Diagram for a Power Park Module electrically equivalent
system the data should be on a 100MVA base. Depending on the equivalent system
supplied an equivalent tap changer range may need to be supplied. Similarly mutual values,
rated voltage and operating voltage may be inappropriate. Additionally in the case of
OTSUA, seasonal maximum continuous ratings and circuit lengths are to be provided in
addition to the data required under PC.A.2.2.4.
PC.A.2.2.5
For each transformer shown on the Single Line Diagram provided under PC.A.2.2.1, each User
(including those undertaking OTSDUW) shall provide the following details:
Rated MVA
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Voltage Ratio
Winding arrangement
Positive sequence reactance (max, min and nominal tap)
Positive sequence resistance (max, min and nominal tap)
Zero sequence reactance
PC.A.2.2.5.1.
In addition, for all interconnecting transformers between the User's Supergrid Voltage System
and the User's Subtransmission System throughout Great Britain and, in Scotland and
Offshore, also for all interconnecting transformers between the User’s 132kV System and the
User’s Subtransmission System (and any OTSUA) the User shall supply the following
information:Tap changer range
Tap change step size
Tap changer type: on load or off circuit
Earthing method: Direct, resistance or reactance
Impedance (if not directly earthed )
PC.A.2.2.6
Each User shall supply the following information about the User’s equipment installed at a
Transmission Site (or in the case of OTSUA, all OTSDUW Plant and Apparatus):(a) Switchgear. For all circuit breakers:Rated voltage (kV)
Operating voltage (kV)
Rated 3-phase rms short-circuit breaking current, (kA)
Rated 1-phase rms short-circuit breaking current, (kA)
Rated 3-phase peak short-circuit making current, (kA)
Rated 1-phase peak short-circuit making current, (kA)
Rated rms continuous current (A)
DC time constant applied at testing of asymmetrical breaking abilities (secs)
In the case of OTSDUW Plant and Apparatus operating times for circuit breaker,
Protection, trip relay and total operating time should be provided.
(b) Substation Infrastructure. For the substation infrastructure (including, but not limited to,
switch disconnectors, disconnectors, current transformers, line traps, busbars, through
bushings, etc):Rated 3-phase rms short-circuit withstand current (kA)
Rated 1-phase rms short-circuit withstand current (kA).
Rated 3-phase short-circuit peak withstand current (kA)
Rated 1- phase short-circuit peak withstand current (kA)
Rated duration of short circuit withstand (secs)
Rated rms continuous current (A)
A single value for the entire substation may be supplied, provided it represents the most
restrictive item of current carrying apparatus.
PC.A.2.2.7
In the case of OTSUA the following should also be provided
(a) Automatic switching scheme schedules including diagrams and an explanation of how the
System will operate and what plant will be affected by the schemes Operation.
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(b) Intertripping schemes both Generation and Demand. In each case a diagram of the
scheme and an explanation of how the System will operate and what Plant will be affected
by the schemes Operation.
PC.A.2.3
Lumped System Susceptance
PC.A.2.3.1
For all parts of the User’s Subtransmission System (and any OTSUA) which are not included in
the Single Line Diagram provided under PC.A.2.2.1, each User shall provide the equivalent
lumped shunt susceptance at nominal Frequency.
PC.A.2.3.1.1
This should include shunt reactors connected to cables which are not normally in or out of service
independent of the cable (ie. they are regarded as part of the cable).
PC.A.2.3.1.2
This should not include:
(a) independently switched reactive compensation equipment connected to the User's System
specified under PC.A.2.4, or;
(b) any susceptance of the User's System inherent in the Demand (Reactive Power) data
specified under PC.A.4.3.1.
PC.A.2.4
Reactive Compensation Equipment
PC.A.2.4.1
For all independently switched reactive compensation equipment (including any OTSUA),
including that shown on the Single Line Diagram, not operated by NGET and connected to the
User's System at 132kV and above in England and Wales and 33kV and above in Scotland and
Offshore (including any OTSDUW Plant and Apparatus operating at High Voltage), other than
power factor correction equipment associated directly with Customers' Plant and Apparatus, the
following information is required:
(a) type of equipment (eg. fixed or variable);
(b) capacitive and/or inductive rating or its operating range in MVAr;
(c) details of any automatic control logic to enable operating characteristics to be determined;
(d) the point of connection to the User's System (including OTSUA) in terms of electrical
location and System voltage.
(e) In the case of OTSDUW Plant and Apparatus the User should also provide:(i)
Connection node, voltage, rating, power loss, tap range and connection arrangement.
(ii)
A mathematical representation in block diagram format to model the control of any
dynamic compensation plant. The model should be suitable for RMS dynamic stability
type studies where each time constant should be no less than 10ms.
(iii) For Static Var Compensation equipment the User should provide:
HV Node
LV Node
Control Node
Nominal Voltage (kV)
Target Voltage (kV)
Maximum MVAr at HV
Minimum MVAr at HV
Slope %
Voltage dependant Q Limit
Normal Running Mode
Postive and zero phase sequence resistance and reactance
Transformer winding type
Connection arrangements
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PC.A.2.4.2
DC Converter Station owners (and a User where the OTSUA includes an OTSDUW DC
Converter) are also required to provide information about the reactive compensation and
harmonic filtering equipment required to ensure that their Plant and Apparatus (and the OTSUA)
complies with the criteria set out in CC.6.1.5.
PC.A.2.5
Short Circuit Contribution to National Electricity Transmission System
PC.A.2.5.1
General
(a) To allow NGET to calculate fault currents, each User is required to provide data, calculated
in accordance with Good Industry Practice, as set out in the following paragraphs of
PC.A.2.5.
(b) The data should be provided for the User's System with all Generating Units, Power Park
Units and DC Converters Synchronised to that User's System (and any OTSUA where
appropriate). The User must ensure that the pre-fault network conditions reflect a credible
System operating arrangement.
(c) The list of data items required, in whole or part, under the following provisions, is set out in
PC.A.2.5.6. Each of the relevant following provisions identifies which data items in the list
are required for the situation with which that provision deals.
The fault currents in sub-paragraphs (a) and (b) of the data list in PC.A.2.5.6 should be
based on an a.c. load flow that takes into account any pre-fault current flow across the Point
of Connection (and in the case of OTSUA, Interface Points and Connection Points) being
considered.
Measurements made under appropriate System conditions may be used by the User to
obtain the relevant data.
(d) NGET may at any time, in writing, specifically request for data to be provided for an
alternative System condition, for example minimum plant, and the User will, insofar as such
request is reasonable, provide the information as soon as reasonably practicable following
the request.
PC.A.2.5.2
Network Operators and Non-Embedded Customers are required to submit data in accordance
with PC.A.2.5.4. Generators, DC Converter Station owners and Network Operators, in
respect of Embedded Medium Power Stations not subject to a Bilateral Agreement and
Embedded DC Converter Stations not subject to a Bilateral Agreement within such Network
Operator’s Systems are required to submit data in accordance with PC.A.2.5.5.
PC.A.2.5.3
Where prospective short-circuit currents on equipment owned, operated or managed by NGET
are close to the equipment rating, and in NGET’s reasonable opinion more accurate calculations
of the prospective short circuit currents are required, then NGET will request additional data as
outlined in PC.A.6.6 below.
PC.A.2.5.4
Data from Network Operators and Non-Embedded Customers
PC.A.2.5.4.1
Data is required to be provided at each node on the Single Line Diagram provided under
PC.A.2.2.1 at which motor loads and/or Embedded Small Power Stations and/or Embedded
Medium Power Stations and/or Embedded installations of direct current converters which do
not form a DC Converter Station are connected, assuming a fault at that location, as follows:The data items listed under the following parts of PC.A.2.5.6:(a) (i), (ii), (iii), (iv), (v) and (vi);
and the data items shall be provided in accordance with the detailed provisions of PC.A.2.5.6(c) (f).
PC.A.2.5.4.2
Network Operators shall provide the following data items in respect of each Interface Point
within their User System:
(a) Maximum Export Capacity;
(b) Maximum Import Capacity; and,
(c) Interface Point Target Voltage/Power Factor
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Network Operators shall alongside these parameters include details of any manual or automatic
post fault actions to be taken by the owner / operator of the Offshore Transmission System
connected to such Interface Point that are required by the Network Operator.
PC.A.2.5.5
Data from Generators (including Generators undertaking OTSDUW), DC Converter Station
owners and from Network Operators in respect of Embedded Medium Power Stations not subject
to a Bilateral Agreement and Embedded DC Converter Stations not subject to a Bilateral
Agreement within such Network Operator’s Systems.
PC.A.2.5.5.1
For each Generating Unit with one or more associated Unit Transformers, the Generator, or
the Network Operator in respect of Embedded Medium Power Stations not subject to a
Bilateral Agreement and Embedded DC Converter Stations not subject to a Bilateral
Agreement within such Network Operator’s System is required to provide values for the
contribution of the Power Station Auxiliaries (including Auxiliary Gas Turbines or Auxiliary
Diesel Engines) to the fault current flowing through the Unit Transformer(s).
The data items listed under the following parts of PC.A.2.5.6(a) should be provided:(i), (ii) and (v);
(iii) if the associated Generating Unit step-up transformer can supply zero phase
sequence current from the Generating Unit side to the National Electricity
Transmission System;
(iv) if the value is not 1.0 p.u;
and the data items shall be provided in accordance with the detailed provisions of PC.A.2.5.6(c) (f), and with the following parts of this PC.A.2.5.5.
PC.A.2.5.5.2
Auxiliary motor short circuit current contribution and any Auxiliary Gas Turbine Unit contribution
through the Unit Transformers must be represented as a combined short circuit current
contribution at the Generating Unit's terminals, assuming a fault at that location.
PC.A.2.5.5.3
If the Power Station or DC Converter Station (or OTSDUW Plant and Apparatus which
provides a fault infeed) has separate Station Transformers, data should be provided for the fault
current contribution from each transformer at its high voltage terminals, assuming a fault at that
location, as follows:The data items listed under the following parts of PC.A.2.5.6
(a) (i), (ii), (iii), (iv), (v) and (vi);
and the data items shall be provided in accordance with the detailed provisions of PC.A.2.5.6(b) (f).
PC.A.2.5.5.4
Data for the fault infeeds through both Unit Transformers and Station Transformers shall be
provided for the normal running arrangement when the maximum number of Generating Units
are Synchronised to the System or when all the DC Converters at a DC Converter Station are
transferring Rated MW in either direction. Where there is an alternative running arrangement (or
transfer in the case of a DC Converter Station) which can give a higher fault infeed through the
Station Transformers, then a separate data submission representing this condition shall be
made.
PC.A.2.5.5.5
Unless the normal operating arrangement within the Power Station is to have the Station and
Unit Boards interconnected within the Power Station, no account should be taken of the
interconnection between the Station Board and the Unit Board.
PC.A.2.5.5.6
Auxiliary motor short circuit current contribution and any auxiliary DC Converter Station
contribution through the Station Transformers must be represented as a combined short circuit
current contribution through the Station Transformers.
PC.A.2.5.5.7
Where a Manufacturer’s Data & Performance Report exists in respect of the model of the
Power Park Unit, the User may opt to reference the Manufacturer’s Data & Performance
Report as an alternative to the provision of data in accordance with this PC.A.2.5.5.7. For the
avoidance of doubt, all other data provision pursuant to the Grid Code shall still be provided
including a Single Line Diagram and those data pertaining thereto.
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For each Power Park Module and each type of Power Park Unit (eg. Doubly Fed Induction
Generator) (and any OTSDUW Plant and Apparatus which provides a fault infeed), including
any Auxiliaries, positive, negative and zero sequence root mean square current values are to be
provided of the contribution to the short circuit current flowing at:
(i)
the Power Park Unit terminals, or the Common Collection Busbar if an equivalent Single
Line Diagram and associated data as described in PC.A.2.2.2 is provided, and
(ii)
the Grid Entry Point (and in case of OTSUA, Transmission Interface Point), or User
System Entry Point if Embedded
for the following solid faults at the Grid Entry Point (and in case of OTSUA, Interface Point), or
User System Entry Point if Embedded:
(i)
a symmetrical three phase short circuit
(ii)
a single phase to earth short circuit
(iii) a phase to phase short circuit
(iv) a two phase to earth short circuit
For a Power Park Module in which one or more of the Power Park Units utilise a protective
control such as a crowbar circuit, the data should indicate whether the protective control will act
in each of the above cases and the effects of its action shall be included in the data. For any
case in which the protective control will act, the data for the fault shall also be submitted for the
limiting case in which the protective circuit will not act, which may involve the application of a
non-solid fault, and the positive, negative and zero sequence retained voltages at
(i)
the Power Park Unit terminals, or the Common Collection Busbar if an equivalent Single
Line Diagram and associated data is provided and
(ii)
the Grid Entry Point, or User System Entry Point if Embedded
in this limiting case shall be provided.
For each fault for which data is submitted, the data items listed under the following parts of
PC.A.2.5.6(a) shall be provided:(iv), (vii), (viii), (ix), (x);
In addition, if an equivalent Single Line Diagram has been provided the data items listed under
the following parts of PC.A.2.5.6(a) shall be provided:(xi), (xii), (xiii);
In addition, for a Power Park Module in which one or more of the Power Park Units utilise a
protective control such as a crowbar circuit:the data items listed under the following parts of PC.A.2.5.6(a) shall be provided:(xiv), (xv);
All of the above data items shall be provided in accordance with the detailed provisions of
PC.A.2.5.6(c), (d), (f).
Should actual data in respect of fault infeeds be unavailable at the time of the application for a
CUSC Contract or Embedded Development Agreement, a limited subset of the data,
representing the maximum fault infeed that may result from all of the plant types being
considered, shall be submitted. This data will, as a minimum, represent the root mean square of
the positive, negative and zero sequence components of the fault current for both single phase
and three phase solid faults at the Grid Entry Point (or User System Entry Point if Embedded)
at the time of fault application and 50ms following fault application. Actual data in respect of fault
infeeds shall be submitted to NGET as soon as it is available, in line with PC.A.1.2
PC.A.2.5.6
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(a) The following is the list of data utilised in this part of the PC. It also contains rules on the
data which generally apply:(i)
Root mean square of the symmetrical three-phase short circuit current infeed at the
instant of fault, (I1");
(ii)
Root mean square of the symmetrical three-phase short circuit current after the
subtransient fault current contribution has substantially decayed, (I1');
(iii) the zero sequence source resistance and reactance values of the User's System as
seen from the node on the Single Line Diagram provided under PC.A.2.2.1 (or Station
Transformer high voltage terminals or Generating Unit terminals or DC Converter
terminals, as appropriate) consistent with the infeed described in PC.A.2.5.1.(b);
(iv) root mean square of the pre-fault voltage at which the maximum fault currents were
calculated;
(v)
the positive sequence X/R ratio at the instant of fault;
(vi) the negative sequence resistance and reactance values of the User's System seen
from the node on the Single Line Diagram provided under PC.A.2.2.1 (or Station
Transformer high voltage terminals, or Generating Unit terminals or DC Converter
terminals if appropriate) if substantially different from the values of positive sequence
resistance and reactance which would be derived from the data provided above;
(vii) A continuous trace and a table showing the root mean square of the positive, negative
and zero sequence components of the short circuit current between zero and 140ms at
10ms intervals;
(viii) The Active Power (or Interface Point Capacity being exported pre-fault by the
OTSDUW Plant and Apparatus) being generated pre-fault by the Power Park Module
and by each type of Power Park Unit;
(ix) The reactive compensation shown explicitly on the Single Line Diagram that is
switched in;
(x)
The Power Factor of the Power Park Module and of each Power Park Unit type;
(xi) The positive sequence X/R ratio of the equivalent at the Common Collection Busbar
or Interface Point in the case of OTSUA;
(xii) The minimum zero sequence impedance of the equivalent seen from the Common
Collection Busbar or Interface Point in the case of OTSUA ;
(xiii) The number of Power Park Units represented in the equivalent Power Park Unit;
(xiv) The additional rotor resistance and reactance (if any) that is applied to the Power Park
Unit under a fault condition;
(xv) A continuous trace and a table showing the root mean square of the positive, negative
and zero sequence components of the retained voltage at the fault point and Power
Park Unit terminals, or the Common Collection Busbar if an equivalent Single Line
Diagram and associated data as described in PC.A.2.2.2 is provided or Interface
Point in the case of OTSUA, representing the limiting case, which may involve the
application of a non-solid fault, required to not cause operation of the protective control;
(b) In considering this data, unless the User notifies NGET accordingly at the time of data
submission, NGET will assume that the time constant of decay of the subtransient fault
current corresponding to the change from I1" to I1', (T") is not significantly different from
40ms. If that assumption is not correct in relation to an item of data, the User must inform
NGET at the time of submission of the data.
(c) The value for the X/R ratio must reflect the rate of decay of the d.c. component that may be
present in the fault current and hence that of the sources of the initial fault current. All shunt
elements and loads must therefore be deleted from any system model before the X/R ratio is
calculated.
(d) In producing the data, the User may use "time step analysis" or "fixed-point-in-time analysis"
with different impedances.
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(e) If a fixed-point-in-time analysis with different impedances method is used, then in relation to
the data submitted under (a) (i) above, the data will be required for "time zero" to give I 1".
The figure of 120ms is consistent with a decay time constant T" of 40ms, and if that figure is
different, then the figure of 120ms must be changed accordingly.
(f)
Where a "time step analysis" is carried out, the X/R ratio may be calculated directly from the
rate of decay of the d.c. component. The X/R ratio is not that given by the phase angle of
the fault current if this is based on a system calculation with shunt loads, but from the
Thévenin equivalent of the system impedance at the instant of fault with all non-source
shunts removed.
PC.A.3
GENERATING UNIT AND DC CONVERTER DATA
PC.A.3.1
Introduction
Directly Connected
PC.A.3.1.1
Each Generator and DC Converter Station owner (and a User where the OTSUA includes an
OTSDUW DC Converter) with an existing, or proposed, Power Station or DC Converter Station
directly connected, or to be directly connected, to the National Electricity Transmission System
(or in the case of OTSUA, the Interface Point), shall provide NGET with data relating to that
Power Station or DC Converter Station, both current and forecast, as specified in PC.A.3.2 to
PC.A.3.4.
Embedded
PC.A.3.1.2
(a) Each Generator and DC Converter Station owner in respect of its existing, and/or
proposed, Embedded Large Power Stations and/or Embedded DC Converter Stations
and/or its Embedded Medium Power Stations subject to a Bilateral Agreement and each
Network Operator in respect of its Embedded Medium Power Stations not subject to a
Bilateral Agreement and/or Embedded DC Converter Stations not subject to a Bilateral
Agreement within such Network Operator’s System in each case connected to the
Subtransmission System, shall provide NGET with data relating to that Power Station or
DC Converter Station, both current and forecast, as specified in PC.A.3.2 to PC.A.3.4.
(b) No data need be supplied in relation to any Small Power Station or any Medium Power
Station or installations of direct current converters which do not form a DC Converter
Station, connected at a voltage level below the voltage level of the Subtransmission
System except:-
PC.A.3.1.3
(i)
in connection with an application for, or under, a CUSC Contract, or
(ii)
unless specifically requested by NGET under PC.A.3.1.4.
(a) Each Network Operator shall provide NGET with the data specified in PC.A.3.2.2(c)(i)
and (ii) and PC.A.3.2.2(i).
(b) Network Operators need not submit planning data in respect of an Embedded Small
Power Station unless required to do so under PC.A.1.2(b) or unless specifically requested
under PC.A.3.1.4 below, in which case they will supply such data.
PC.A.3.1.4
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(a) PC.A.4.2.4(b) and PC.A.4.3.2(a) explain that the forecast Demand submitted by each
Network Operator must be net of the output of all Small Power Stations and Medium
Power Stations and Customer Generating Plant and all installations of direct current
converters which do not form a DC Converter Station, Embedded within that Network
Operator’s System. The Network Operator must inform NGET of:
(i)
the number of such Embedded Power Stations and such Embedded installations of
direct current converters (including the number of Generating Units or Power Park
Modules or DC Converters) together with their summated capacity; and
(ii)
beginning from the 2015 Week 24 data submission, for each Embedded Small Power
Station of registered capacity (as defined in the Distribution Code) of 1MW or more:
1.
A reference which is unique to each Network Operator;
2.
The production type as follows:
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a)
In the case of an Embedded Small Power Station first connected on or
after 1 January 2015, the production type must be selected from the list
below derived from the Manual of Procedures for the ENTSO-E Central
Information Transparency Platform:
-
Biomass;
-
Fossil brown coal/lignite;
-
Fossil coal-derived gas;
-
Fossil gas;
-
Fossil hard coal;
-
Fossil oil;
-
Fossil oil shale;
-
Fossil peat;
-
Geothermal;
-
Hydro pumped storage;
-
Hydro run-of-river and poundage;
-
Hydro water reservoir;
-
Marine;
-
Nuclear;
-
Other renewable;
-
Solar;
-
Waste;
-
Wind offshore;
-
Wind onshore; or
-
Other;
together with a statement as to whether the generation forms part of a
CHP scheme;
b)
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In the case of an Embedded Small Power Station first connected to the
Users’ System before 1 January 2015, as an alternative to the
production type, the technology type(s) used, selected from the list set
out at paragraph 2.23 in Version 2 of the Regulatory Instructions and
Guidance relating to the distributed generation incentive, innovation
funding incentive and registered power zones, reference 83/07,
published by Ofgem in April 2007;
3.
The registered capacity (as defined in the Distribution Code) in MW;
4.
The lowest voltage level node that is specified on the most up-to-date Single Line
Diagram to which it connects or where it will export most of its power;
5.
Where it generates electricity from wind or PV, the geographical location using
either latitude or longitude or grid reference coordinates of the primary or higher
voltage substation to which it connects;
6.
The reactive power and voltage control mode, including the voltage set-point and
reactive range, where it operates in voltage control mode, or the target Power
Factor, where it operates in Power Factor mode;
7.
Details of the types of loss of mains Protection in place and their relay settings
which in the case of Embedded Small Power Stations first connected to the
Users’ System before 1 January 2015 shall be provided on a reasonable
endeavours basis.
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(b) On receipt of this data, the Network Operator or Generator (if the data relates to Power
Stations referred to in PC.A.3.1.2) may be further required, at NGET's reasonable
discretion, to provide details of Embedded Small Power Stations and Embedded Medium
Power Stations and Customer Generating Plant and Embedded installations of direct
current converters which do not form a DC Converter Station, both current and forecast, as
specified in PC.A.3.2 to PC.A.3.4. Such requirement would arise where NGET reasonably
considers that the collective effect of a number of such Embedded Power Stations and
Customer Generating Plants and Embedded installations of direct current converters may
have a significant system effect on the National Electricity Transmission System.
Busbar Arrangements
PC.A.3.1.5
Where Generating Units, which term includes CCGT Units and Power Park Modules, and DC
Converters, are connected to the National Electricity Transmission System via a busbar
arrangement which is or is expected to be operated in separate sections, the section of busbar to
which each Generating Unit, DC Converter or Power Park Module is connected is to be
identified in the submission.
PC.A.3.2
Output Data
PC.A.3.2.1
(a) Large Power Stations and Gensets
Data items PC.A.3.2.2 (a), (b), (c), (d), (e), (f) and (h) are required with respect to each
Large Power Station and each Generating Unit and Power Park Module of each Large
Power Station and for each Genset (although (a) is not required for CCGT Units and (b),
(d) and (e) are not normally required for CCGT Units and (a), (b), (c), (d), (e), (f) and (h) are
not normally required for Power Park Units).
(b) Embedded Small Power Stations and Embedded Medium Power Stations
Data item PC.A.3.2.2 (a) is required with respect to each Embedded Small Power Station
and Embedded Medium Power Station and each Generating Unit and Power Park
Module of each Embedded Small Power Station and Embedded Medium Power Station
(although (a) is not required for CCGT Units or Power Park Units).In addition, data item
PC.A.3.2.2(c)(ii) is required with respect to each Embedded Medium Power Station.
(c) CCGT Units/Modules
(i)
Data item PC.A.3.2.2 (g) is required with respect to each CCGT Unit;
(ii)
data item PC.A.3.2.2 (a) is required with respect to each CCGT Module; and
(iii) data items PC.A.3.2.2 (b), (c), (d) and (e) are required with respect to each CCGT
Module unless NGET informs the relevant User in advance of the submission that it
needs the data items with respect to each CCGT Unit for particular studies, in which
case it must be supplied on a CCGT Unit basis.
Where any definition utilised or referred to in relation to any of the data items does not
reflect CCGT Units, such definition shall be deemed to relate to CCGT Units for the
purposes of these data items. Any Schedule in the DRC which refers to these data items
shall be interpreted to incorporate the CCGT Unit basis where appropriate;
(d) Cascade Hydro Schemes
Data item PC.A.3.2.2(i) is required with respect to each Cascade Hydro Scheme.
(e) Power Park Units/Modules
Data items PC.A.3.2.2 (k) is required with respect to each Power Park Module.
(f)
DC Converters
Data items PC.A.3.2.2 (a), (b), (c), (d) (e) (f) (h) and (i) are required with respect to each DC
Converter Station and each DC Converter in each DC Converter Station. For installations
of direct current converters which do not form a DC Converter Station only data item
PC.A.3.2.2.(a) is required.
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PC.A.3.2.2
Items (a), (b), (d), (e), (f), (g), (h), (i), (j) and (k) are to be supplied by each Generator, DC
Converter Station owner or Network Operator (as the case may be) in accordance with
PC.A.3.1.1, PC.A.3.1.2, PC.A.3.1.3 and PC.A.3.1.4. Items (a), and (f)(iv) are to be supplied (as
applicable) by a User in the case of OTSUA which includes an OTSDUW DC Converter. Item (c)
is to be supplied by each Network Operator in all cases:(a) Registered Capacity (MW) or Interface Point Capacity in the case of OTSDUW;
(b) Output Usable (MW) on a monthly basis;
(c) (i)
(ii)
System Constrained Capacity (MW) ie. any constraint placed on the capacity of the
Embedded Generating Unit, Embedded Power Park Module, an Offshore
Transmission System at an Interface Point or DC Converter at an Embedded DC
Converter Station due to the Network Operator’s System in which it is Embedded.
Where Generating Units (which term includes CCGT Units), Power Park Modules,
Offshore Transmission Systems at an Interface Point or DC Converters are
connected to a Network Operator’s User System via a busbar arrangement which is
or is expected to be operated in separate sections, details of busbar running
arrangements and connected circuits at the substation to which the Embedded
Generating Unit, Embedded Power Park Module, Offshore Transmission System
at an Interface Point or Embedded DC Converter is connected sufficient for NGET to
determine where the MW generated by each Generating Unit, Power Park Module or
DC Converter at that Power Station or DC Converter Station or Offshore
Transmission System at an Interface Point would appear onto the National
Electricity Transmission System;
any Reactive Despatch Network Restrictions;
(d) Minimum Generation (MW);
(e) MW obtainable from Generating Units, Power Park Modules or DC Converters at a DC
Converter Station in excess of Registered Capacity;
(f)
Generator Performance Chart:
(i)
at the Onshore Synchronous Generating Unit stator terminals
(ii)
at the electrical point of connection to the Offshore Transmission System for an
Offshore Synchronous Generating Unit.
(iii) at the electrical point of connection to the National Electricity Transmission System
(or User System if Embedded) for a Non Synchronous Generating Unit (excluding a
Power Park Unit), Power Park Module and DC Converter at a DC Converter
Station;
(iv) at the Interface Point for OTSDUW Plant and Apparatus
Where a Reactive Despatch Network Restriction applies, its existence and details should
be highlighted on the Generator Performance Chart, in sufficient detail for NGET to
determine the nature of the restriction.
(g) a list of the CCGT Units within a CCGT Module, identifying each CCGT Unit, and the
CCGT Module of which it forms part, unambiguously. In the case of a Range CCGT
Module, details of the possible configurations should also be submitted, together:(i)
(in the case of a Range CCGT Module connected to the National Electricity
Transmission System) with details of the single Grid Entry Point (there can only be
one) at which power is provided from the Range CCGT Module;
(ii)
(in the case of an Embedded Range CCGT Module) with details of the single User
System Entry Point (there can only be one) at which power is provided from the
Range CCGT Module;
Provided that, nothing in this sub-paragraph (g) shall prevent the busbar at the relevant point
being operated in separate sections;
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(h) expected running regime(s) at each Power Station or DC Converter Station and type of
Generating Unit, eg. Steam Unit, Gas Turbine Unit, Combined Cycle Gas Turbine Unit,
Power Park Module, Novel Units (specify by type), etc;
(i)
(j)
a list of Power Stations and Generating Units within a Cascade Hydro Scheme,
identifying each Generating Unit and Power Station and the Cascade Hydro Scheme
of which each form part unambiguously. In addition:
(i)
details of the Grid Entry Point at which Active Power is provided, or if
Embedded the Grid Supply Point(s) within which the Generating Unit is
connected;
(ii)
where the Active Power output of a Generating Unit is split between more than
one Grid Supply Points the percentage that would appear under normal and
outage conditions at each Grid Supply Point.
The following additional items are only applicable to DC Converters at DC Converter
Stations.
Registered Import Capacity (MW);
Import Usable (MW) on a monthly basis;
Minimum Import Capacity (MW);
MW that may be absorbed by a DC Converter in excess of Registered Import
Capacity and the duration for which this is available;
(k)
PC.A.3.2.3
the number and types of the Power Park Units within a Power Park Module, identifying
each Power Park Unit, the Power Park Module of which it forms part and identifying the
BM Unit of which each Power Park Module forms part, unambiguously. In the case of a
Power Station directly connected to the National Electricity Transmission System with
multiple Power Park Modules where Power Park Units can be selected to run in different
Power Park Modules and/or Power Park Modules can be selected to run in different BM
Units, details of the possible configurations should also be submitted. In addition for
Offshore Power Park Modules, the number of Offshore Power Park Strings that are
aggregated into one Offshore Power Park Module should also be submitted.
Notwithstanding any other provision of this PC, the CCGT Units within a CCGT Module, details
of which are required under paragraph (g) of PC.A.3.2.2, can only be amended in accordance
with the following provisions:(a) if the CCGT Module is a Normal CCGT Module, the CCGT Units within that CCGT Module
can only be amended such that the CCGT Module comprises different CCGT Units if NGET
gives its prior consent in writing. Notice of the wish to amend the CCGT Units within such a
CCGT Module must be given at least 6 months before it is wished for the amendment to
take effect;
(b) if the CCGT Module is a Range CCGT Module, the CCGT Units within that CCGT Module
and the Grid Entry Point at which the power is provided can only be amended as described
in BC1.A1.6.4.
PC.A.3.2.4
Notwithstanding any other provision of this PC, the Power Park Units within a Power Park
Module, and the Power Park Modules within a BM Unit, details of which are required under
paragraph (k) of PC.A.3.2.2, can only be amended in accordance with the following provisions:(a) if the Power Park Units within that Power Park Module can only be amended such that the
Power Park Module comprises different Power Park Units due to repair/replacement of
individual Power Park Units if NGET gives its prior consent in writing. Notice of the wish to
amend a Power Park Unit within such a Power Park Module must be given at least 4
weeks before it is wished for the amendment to take effect;
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(b) if the Power Park Units within that Power Park Module and/or the Power Park Modules
within that BM Unit can be selected to run in different Power Park Modules and/or BM
Units as an alternative operational running arrangement the Power Park Units within the
Power Park Module, the BM Unit of which each Power Park Module forms part, and the
Grid Entry Point at which the power is provided can only be amended as described in
BC1.A.1.8.4.
PC.A.3.3.
Rated Parameters Data
PC.A.3.3.1
The following information is required to facilitate an early assessment, by NGET, of the need for
more detailed studies;
(a) for all Generating Units (excluding Power Park Units) and Power Park Modules:
Rated MVA
Rated MW;
(b) for each Synchronous Generating Unit:
Short circuit ratio
Direct axis transient reactance;
Inertia constant (for whole machine), MWsecs/MVA;
(c) for each Synchronous Generating Unit step-up transformer:
Rated MVA
Positive sequence reactance (at max, min and nominal tap);
(d) for each DC Converter at a DC Converter Station or DC Converter connecting a Power
Park Module (including when forming part of OTSUA).
DC Converter type (e.g. current/voltage sourced)
Rated MW per pole for import and export
Number of poles and pole arrangement
Rated DC voltage/pole (kV)
Return path arrangement
Remote AC connection arrangement (excluding OTSDUW DC Converters)
(e) for each type of Power Park Unit in a Power Park Module not connected to the Total
System by a DC Converter:
Rated MVA
Rated MW
Rated terminal voltage
Inertia constant, (MWsec/MVA)
Additionally, for Power Park Units that are squirrel-cage or doubly-fed induction
generators driven by wind turbines:
Stator reactance.
Magnetising reactance.
Rotor resistance (at rated running)
Rotor reactance (at rated running)
The generator rotor speed range (minimum and maximum speeds in RPM) (for
doubly-fed induction generators only)
Converter MVA rating (for doubly-fed induction generators only)
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For a Power Park Unit consisting of a synchronous machine in combination with a back-toback DC Converter, or for a Power Park Unit not driven by a wind turbine, the data to be
supplied shall be agreed with NGET in accordance with PC.A.7.
This information should only be given in the data supplied in accordance with PC.4.4 and PC.4.5.
PC.A.3.4
General Generating Unit Power Park Module and DC Converter Data
PC.A.3.4.1
The point of connection to the National Electricity Transmission System or the Total System,
if other than to the National Electricity Transmission System, in terms of geographical and
electrical location and system voltage is also required.
PC.A.3.4.2
(a) Type of Generating Unit (ie Synchronous Generating Unit, Non-Synchronous
Generating Unit, DC Converter or Power Park Module).
(b) In the case of a Synchronous Generating Unit details of the Exciter category, for example
whether it is a rotating Exciter or a static Exciter or in the case of a Non-Synchronous
Generating Unit the voltage control system.
(c) Whether a Power System Stabiliser is fitted.
PC.A.3.4.3
Each Generator shall supply NGET with the production type(s) used as the primary source of
power in respect of each Generating Unit, selected from the list set out below:
-
Biomass
-
Fossil brown coal/lignite
-
Fossil coal-derived gas
-
Fossil gas
-
Fossil hard coal
-
Fossil oil
-
Fossil oil shale
-
Fossil peat
-
Geothermal
-
Hydro pumped storage
-
Hydro run-of-river and poundage
-
Hydro water reservoir
-
Marine
-
Nuclear
-
Other renewable
-
Solar
-
Waste
-
Wind offshore
-
Wind onshore
-
Other
PC.A.4
DEMAND AND ACTIVE ENERGY DATA
PC.A.4.1
Introduction
PC.A.4.1.1
Each User directly connected to the National Electricity Transmission System with Demand
shall provide NGET with the Demand data, historic, current and forecast, as specified in
PC.A.4.2 and PC.A.4.3. Paragraphs PC.A.4.1.2 and PC.A.4.1.3 apply equally to Active Energy
requirements as to Demand unless the context otherwise requires.
PC.A.4.1.2
Data will need to be supplied by:
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(a) each Network Operator, in relation to Demand and Active Energy requirements on its
User System;
(b) each Non-Embedded Customer (including Pumped Storage Generators with respect to
Pumping Demand) in relation to its Demand and Active Energy requirements.
(c) each DC Converter Station owner in relation to Demand and Active Energy transferred
(imported) to its DC Converter Station.
(d) each OTSDUW DC Converter in relation to the Demand at each Interface Point and
Connection Point.
Demand of Power Stations directly connected to the National Electricity Transmission
System is to be supplied by the Generator under PC.A.5.2.
PC.A.4.1.3
References in this PC to data being supplied on a half hourly basis refer to it being supplied for
each period of 30 minutes ending on the hour or half-hour in each hour.
PC.A.4.1.4
Access Periods and Access Groups
PC.A.4.1.4.1
Each Connection Point must belong to one, and only one, Access Group.
PC.A.4.1.4.2
Each Transmission Interface Circuit must have an Access Period.
PC.A.4.1.4.3
The Access Period shall
(a) normally be a minimum of 8 continuous weeks and can occur in any one of three
maintenance years during the period from calendar week 13 to calendar week 43 (inclusive)
in each year; or,
(b) exceptionally and provided that agreement is reached between NGET and the relevant
User(s), such agreement to be sought in accordance with PC.7, the Access Period may be
of a period not less than 4 continuous weeks and can occur in any one of three maintenance
years during the period from calendar week 10 to calendar week 43 (inclusive) in each year.
PC.A.4.1.4.4
NGET shall submit in writing no later than calendar week 6 in each year:
(a) the calendar weeks defining the proposed start and finish of each Access Period for each
Transmission Interface Circuit; and
(b) the Connection Points in each Access Group.
The submission by NGET under PC.A.4.1.4.4 (a) above shall commence in 2010 and shall then
continue each year thereafter. The submission by NGET under PC.A.4.1.4.4 (b) shall commence
in 2009 and then continue each year thereafter.
PC.A.4.1.4.5
It is permitted for Access Periods to overlap in the same Access Group and in the same
maintenance year. However, where possible Access Periods will be sought by NGET that do not
overlap with any other Access Period within that Access Group for each maintenance year.
Where it is not possible to avoid overlapping Access Periods, NGET will indicate to Users by
calendar week 6 its initial view of which Transmission Interface Circuits will need to be
considered out of service concurrently for the purpose of assessing compliance to Licence
Standards. The obligation on NGET to indicate which Transmission Interface Circuits will
need to be considered out of service concurrently for the purpose of assessing compliance to
Licence Standards shall commence in 2010 and shall continue each year thereafter.
PC.A.4.1.4.6
Following the submission(s) by NGET by week 6 in each year and where required by either party,
both NGET and the relevant User(s) shall use their reasonable endeavours to agree the
appropriate Access Group(s) and Access Period for each Transmission Interface Circuit prior
to week 17 in each year. The requirement on NGET and the relevant User(s) to agree, shall
commence in respect of Access Groups only in 2010. This paragraph PC.A.4.1.4.6 shall apply
in its entirety in 2011 and shall then continue each year thereafter.
PC.A.4.1.4.7
In exceptional circumstances, and with the agreement of all parties concerned, where a
Connection Point is specified for the purpose of the Planning Code as electrically independent
Subtransmission Systems, then data submissions can be on the basis of two (or more)
individual Connection Points.
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PC.A.4.2
User’s User System Demand (Active Power) and Active Energy Data
PC.A.4.2.1
Forecast daily Demand (Active Power) profiles, as specified in (a), (b) and (c) below, in respect
of each of the User's User Systems (each summated over all Grid Supply Points in each User
System) are required for:
(a) peak day on each of the User's User Systems (as determined by the User) giving the
numerical value of the maximum Demand (Active Power) that in the Users' opinion could
reasonably be imposed on the National Electricity Transmission System;
(b) day of peak National Electricity Transmission System Demand (Active Power) as
notified by NGET pursuant to PC.A.4.2.2;
(c) day of minimum National Electricity Transmission System Demand (Active Power) as
notified by NGET pursuant to PC.A.4.2.2.
In addition, the total Demand (Active Power) in respect of the time of peak National Electricity
Transmission System Demand in the preceding Financial Year in respect of each of the User's
User Systems (each summated over all Grid Supply Points in each User System) both outturn
and weather corrected shall be supplied.
PC.A.4.2.2
No later than calendar week 17 each year NGET shall notify each Network Operator and NonEmbedded Customer in writing of the following, for the current Financial Year and for each of
the following seven Financial Years, which will, until replaced by the following year’s notification,
be regarded as the relevant specified days and times under PC.A.4.2.1:
(a)the date and time of the annual peak of the National Electricity Transmission System
Demand;
(b) the date and time of the annual minimum of the National Electricity Transmission System
Demand;
(c) the relevant Access Period for each Transmission Interface Circuit; and,
(d) Concurrent Access Periods of two or more Transmission Interface Circuits (if any) that
are situated in the same Access Group.
The submissions by NGET made under PC.A.4.2.1 (c) and PC.A.4.2.1 (d) above shall commence
in 2010 and shall then continue in respect of each year thereafter.
PC.A.4.2.3
The total Active Energy used on each of the Network Operators’ or Non-Embedded
Customers’ User Systems (each summated over all Grid Supply Points in each User System)
in the preceding Financial Year, both outturn and weather corrected, together with a prediction
for the current financial year, is required. Each Active Energy submission shall be subdivided
into the following categories of Customer tariff:
LV1
LV2
LV3
HV
EHV
Traction
Lighting
In addition, the total User System losses and the Active Energy provided by Embedded Small
Power Stations and Embedded Medium Power Stations shall be supplied.
PC.A.4.2.4
All forecast Demand (Active Power) and Active Energy specified in PC.A.4.2.1 and PC.A.4.2.3
shall:
(a) in the case of PC.A.4.2.1(a), (b) and (c), be such that the profiles comprise average Active
Power levels in 'MW' for each time marked half hour throughout the day;
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(b) in the case of PC.A.4.2.1(a), (b) and (c), be that remaining after any deductions reasonably
considered appropriate by the User to take account of the output profile of all Embedded
Small Power Stations and Embedded Medium Power Stations and Customer
Generating Plant and imports across Embedded External Interconnections including
imports across Embedded installations of direct current converters which do not form a DC
Converter Station and Embedded DC Converter Stations with a Registered Capacity of
less than 100MW;
(c) be based upon Annual ACS Conditions for times that occur during week 44 through to
week 12 (inclusive) and based on Average Conditions for weeks 13 to 43 (inclusive).
PC.A.4.3
Connection Point Demand (Active and Reactive Power)
PC.A.4.3.1
Forecast Demand (Active Power) and Power Factor (values of the Power Factor at maximum
and minimum continuous excitation may be given instead where more than 95% of the total
Demand at a Connection Point is taken by synchronous motors) to be met at each Connection
Point within each Access Group is required for:
(a) the time of the maximum Demand (Active Power) at the Connection Point (as determined
by the User) that in the User's opinion could reasonably be imposed on the National
Electricity Transmission System;
(b) the time of peak National Electricity Transmission System Demand as provided by NGET
under PC.A.4.2.2;
(c) the time of minimum National Electricity Transmission System Demand as provided by
NGET under PC.A.4.2.2;
(d) the time of the maximum Demand (Apparent Power) at the Connection Point (as
determined by the User) during the Access Period of each Transmission Interface
Circuit;
(e) at a time specified by either NGET or a User insofar as such a request is reasonable.
Instead of such forecast Demand to be met at each Connection Point within each Access
Group the User may (subject to PC.A.4.3.4) submit such Demand at each node on the Single
Line Diagram.
In addition, the Demand in respect of each of the time periods referred to in PC.A.4.3.1 (a) to (e)
in the preceding Financial Year in respect of each Connection Point within each Access Group
both outturn and weather corrected shall be supplied. The “weather correction” shall normalise
outturn figures to Annual ACS Conditions for times that occur during calendar week 44 through
to calendar week 12 (inclusive) or Average Conditions for the period calendar weeks 13 to
calendar week 43 (inclusive) and shall be performed by the relevant User on a best endeavours
basis.
The submission by a User pursuant to PC.A.4.3.1 (d) shall commence in 2011 and shall then
continue each year thereafter.
PC.A.4.3.2
All forecast Demand specified in PC.A.4.3.1 shall:
(a) be that remaining after any deductions reasonably considered appropriate by the User to
take account of the output of all Embedded Small Power Stations and Embedded Medium
Power Stations and Customer Generating Plant and imports across Embedded External
Interconnections, including Embedded installations of direct current converters which do
not form a DC Converter Station and Embedded DC Converter Stations and such
deductions should be separately stated;
(b) include any User's System series reactive losses but exclude any reactive compensation
equipment specified in PC.A.2.4 and exclude any network susceptance specified in
PC.A.2.3;
(c) be based upon Annual ACS Conditions for times that occur during calendar week 44
through to calendar week 12 (inclusive) and based on Average Conditions for calendar
weeks 13 to calendar week 43 (inclusive), both corrections being made on a best
endeavours basis;
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(d) reflect the User’s opinion of what could reasonably be imposed on the National Electricity
Transmission System.
PC.A.4.3.3
The date and time of the forecast maximum Demand (Apparent Power) at the Connection
Point as specified in PC.A.4.3.1 (a) and (d) is required.
PC.A.4.3.4
Each Single Line Diagram provided under PC.A.2.2.2 shall include the Demand (Active Power)
and Power Factor (values of the Power Factor at maximum and minimum continuous excitation
may be given instead where more than 95% of the Demand is taken by synchronous motors) at
the time of the peak National Electricity Transmission System Demand (as provided under
PC.A.4.2.2) at each node on the Single Line Diagram. These Demands shall be consistent with
those provided under PC.A.4.3.1(b) above for the relevant year.
PC.A.4.3.5
The Single Line Diagram must represent the User’s User System layout under the period
specified in PC.A.4.3.1(b) (at the time of peak National Electricity Transmission System
Demand). Should the User’s User System layout during the other times specified in PC.A.4.3.1
be planned to be materially different from the Single Line Diagram submitted to NGET pursuant
to PC.A.2.2.1 the User shall in respect of such other times submit:
(i)
an alternative Single Line Diagram that accurately reflects the revised layout and in such
case shall also include appropriate associated data representing the relevant changes, or;
(ii)
submit an accurate and unambiguous description of the changes to the Single Line
Diagram previously submitted for the time of peak National Electricity Transmission
System Demand.
Where a User does not submit any changes, NGET will assume that the Single Line Diagram
(and associated circuit and node data) provided at the time of peak National Electricity
Transmission System Demand will be valid for all other times. In respect of such other times,
where the User does not submit such nodal demands at the times defined in PC.A.4.3.1(a), (c),
(d) and (e), the nodal demands will be pro-rata, to be consistent with the submitted Connection
Point Demands.
PC.A.4.4
NGET will assemble and derive in a reasonable manner, the forecast information supplied to it
under PC.A.4.2.1, PC.A.4.3.1, PC.A.4.3.4 and PC.A.4.3.5 above into a cohesive forecast and will
use this in preparing Forecast Demand information in the Seven Year Statement and for use in
NGET's Operational Planning. If any User believes that the cohesive forecast Demand
information in the Seven Year Statement does not reflect its assumptions on Demand, it should
contact NGET to explain its concerns and may require NGET, on reasonable request, to discuss
these forecasts. In the absence of such expressions, NGET will assume that Users concur with
NGET's cohesive forecast.
PC.A.4.5
Post Fault User System Layout
PC.A.4.5.1
Where for the purposes of NGET assessing against the Licence Standards an Access Group,
the User reasonably considers it appropriate that revised post fault User System layouts should
be taken into account by NGET, the following information is required to be submitted by the User:
(i)
the specified Connection Point assessment period (PC.A.4.3.1,(a)-(e)) that is being
evaluated;
(ii)
an accurate and unambiguous description of the Transmission Interface Circuits
considered to be switched out due to a fault;
(iii) appropriate revised Single Line Diagrams and/or associated revised nodal Demand and
circuit data detailing the revised User System(s) conditions;
(iv) where the User’s planned post fault action consists of more than one component, each
component must be explicitly identified using the Single Line Diagram and associated nodal
Demand and circuit data;
(v) the arrangements for undertaking actions (eg the time taken, automatic or manual and any
other appropriate information);.
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The User must not submit any action that it does not have the capability or the intention to
implement during the assessment period specified (subject to there being no further unplanned
outages on the User’s User System).
PC.A.4.6
Control of Demand or Reduction of Pumping Load Offered as Reserve
Magnitude of Demand or pumping load which is tripped
System Frequency at which tripping is initiated
Time duration of System Frequency below trip setting for tripping to
be initiated
Time delay from trip initiation to tripping
MW
Hz
s
s
PC.A.4.7
General Demand Data
PC.A.4.7.1
The following information is infrequently required and should be supplied (wherever possible)
when requested by NGET:
(a) details of any individual loads which have characteristics significantly different from the
typical range of Domestic, Commercial or Industrial loads supplied;
(b) the sensitivity of the Demand (Active and Reactive Power) to variations in voltage and
Frequency on the National Electricity Transmission System at the time of the peak
Demand (Active Power). The sensitivity factors quoted for the Demand (Reactive Power)
should relate to that given under PC.A.4.3.1 and, therefore, include any User's System
series reactive losses but exclude any reactive compensation equipment specified in
PC.A.2.4 and exclude any network susceptance specified in PC.A.2.3;
(c) details of any traction loads, e.g. connection phase pairs and continuous load variation with
time;
(d) the average and maximum phase unbalance, in magnitude and phase angle, which the User
would expect its Demand to impose on the National Electricity Transmission System;
(e) the maximum harmonic content which the User would expect its Demand to impose on the
National Electricity Transmission System;
(f)
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details of all loads which may cause Demand fluctuations greater than those permitted
under Engineering Recommendation P28, Stage 1 at a Point of Common Coupling
including the Flicker Severity (Short Term) and the Flicker Severity (Long Term).
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PART 2 - DETAILED PLANNING DATA
PC.A.5
GENERATING UNIT, POWER PARK MODULE, DC CONVERTER AND OTSDUW PLANT AND
APPARATUS DATA
PC.A.5.1
Introduction
Directly Connected
PC.A.5.1.1
Each Generator (including those undertaking OTSDUW), with existing or proposed Power
Stations directly connected, or to be directly connected, to the National Electricity
Transmission System, shall provide NGET with data relating to that Plant and Apparatus, both
current and forecast, as specified in PC.A.5.2, PC.A.5.3, PC.A.5.4 and PC.A.5.7 as applicable.
Each DC Converter Station owner, with existing or proposed DC Converter Stations (including
Generators undertaking OTSDUW which includes an OTSDUW DC Converter) directly
connected, or to be directly connected, to the National Electricity Transmission System, shall
provide NGET with data relating to that Plant and Apparatus, both current and forecast, as
specified in PC.A.5.2 and PC.A.5.4.
Embedded
PC.A.5.1.2
Each Generator, in respect of its existing, or proposed, Embedded Large Power Stations and
its Embedded Medium Power Stations subject to a Bilateral Agreement and each Network
Operator in respect of Embedded Medium Power Stations not subject to a Bilateral
Agreement within its System shall provide NGET with data relating to each of those Large
Power Stations and Medium Power Stations, both current and forecast, as specified in
PC.A.5.2, PC.A.5.3, PC.A.5.4 and PC.A.5.7 as applicable. Each DC Converter Station owner, or
Network Operator in the case of an Embedded DC Converter Station not subject to a Bilateral
Agreement within its System with existing or proposed DC Converter Stations shall provide
NGET with data relating to each of those DC Converter Stations, both current and forecast, as
specified in PC.A.5.2 and PC.A.5.4. However, no data need be supplied in relation to those
Embedded Medium Power Stations or Embedded DC Converter Stations if they are
connected at a voltage level below the voltage level of the Subtransmission System except in
connection with an application for, or under a, CUSC Contract or unless specifically requested by
NGET under PC.A.5.1.4.
PC.A.5.1.3
Each Network Operator need not submit Planning Data in respect of Embedded Small Power
Stations unless required to do so under PC.A.1.2(b), PC.A.3.1.4 or unless specifically requested
under PC.A.5.1.4 below, in which case they will supply such data.
PC.A.5.1.4
PC.A.4.2.4(b) and PC.A.4.3.2(a) explained that the forecast Demand submitted by each Network
Operator must be net of the output of all Medium Power Stations and Small Power Stations
and Customer Generating Plant Embedded within that User's System. In such cases, the
Network Operator must provide NGET with the relevant information specified under PC.A.3.1.4 .
On receipt of this data further details may be required at NGET's discretion as follows:
(i)
in the case of details required from the Network Operator for Embedded Medium Power
Stations not subject to a Bilateral Agreement and Embedded DC Converter Stations not
subject to a Bilateral Agreement and Embedded Small Power Stations and Embedded
DC Converters in each case within such Network Operator’s System and Customer
Generating Plant; and
(ii)
in the case of details required from the Generator of Embedded Large Power Stations and
Embedded Medium Power Stations subject to a Bilateral Agreement; and
(iii) in the case of details required from the DC Converter Station owner of an Embedded DC
Converter or DC Converter Station subject to a Bilateral Agreement.
both current and forecast, as specified in PC.A.5.2 and PC.A.5.3. Such requirement would arise
when NGET reasonably considers that the collective effect of a number of such Embedded
Small Power Stations, Embedded Medium Power Stations, Embedded DC Converter
Stations, DC Converters and Customer Generating Plants may have a significant system
effect on the National Electricity Transmission System.
PC.A.5.1.5
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The Detailed Planning Data described in this Part 2 of the Appendix comprises both DPD I and
DPD II. The required data is listed and collated in the Data Registration Code. The Users need
to refer to the DRC to establish whether data referred to here is DPD I or DPD II.
PC.A.5.2
Demand
PC.A.5.2.1
For each Generating Unit which has an associated Unit Transformer, the value of the Demand
supplied through this Unit Transformer when the Generating Unit is at Rated MW output is to
be provided.
PC.A.5.2.2
Where the Power Station or DC Converter Station has associated Demand additional to the
unit-supplied Demand of PC.A.5.2.1 which is supplied from either the National Electricity
Transmission System or the Generator's User System the Generator, DC Converter Station
owner or the Network Operator (in the case of Embedded Medium Power Stations not subject
to a Bilateral Agreement within its System), as the case may be, shall supply forecasts for each
Power Station or DC Converter Station of:
(a) the maximum Demand that, in the User's opinion, could reasonably be imposed on the
National Electricity Transmission System or the Generator's User System as
appropriate;
(b) the Demand at the time of the peak National Electricity Transmission System Demand
(c) the Demand at the time of minimum National Electricity Transmission System Demand.
PC.A.5.2.3
No later than calendar week 17 each year NGET shall notify each Generator in respect of its
Large Power Stations and its Medium Power Stations and each DC Converter owner in
respect of its DC Converter Station subject to a Bilateral Agreement and each Network
Operator in respect of each Embedded Medium Power Station not subject to a Bilateral
Agreement and each Embedded DC Converter Station not subject to a Bilateral Agreement
within such Network Operator’s System in writing of the following, for the current Financial
Year and for each of the following seven Financial Years, which will be regarded as the relevant
specified days and times under PC.A.5.2.2:
(a) the date and time of the annual peak of the National Electricity Transmission System
Demand at Annual ACS Conditions;
(b) the date and time of the annual minimum of the National Electricity Transmission System
Demand at Average Conditions.
PC.A.5.2.4
At its discretion, NGET may also request further details of the Demand as specified in PC.A.4.6
PC.A.5.2.5
In the case of OTSDUW Plant and Apparatus the following data shall be supplied:
(a) The maximum Demand that could occur at the Interface Point and each Connection Point
(in MW and MVAr);
(b) Demand at specified time of annual peak half hour of National Electricity Transmission
System Demand at Annual ACS Conditions (in MW and MVAr); and
(c) Demand at specified time of annual minimum half-hour of National Electricity
Transmission System Demand (in MW and MVAr).
For the avoidance of doubt, Demand data associate(d with Generators undertaking OTSDUW
which utilise an OTSDUW DC Converter should supply data under PC.A.4.
PC.A.5.3
Synchronous Generating Unit and Associated Control System Data
PC.A.5.3.1
The data submitted below are not intended to constrain any Ancillary Services Agreement
PC.A.5.3.2
The following Synchronous Generating Unit and Power Station data should be supplied:
(a) Synchronous Generating Unit Parameters
Rated terminal volts (kV)
Maximum terminal voltage set point (kV)
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Terminal voltage set point step resolution – if not continuous (kV)
*
Rated MVA
*
Rated MW
*
Minimum Generation MW
*
Short circuit ratio
Direct axis synchronous reactance
*
Direct axis transient reactance
Direct axis sub-transient reactance
Direct axis short-circuit transient time constant.
Direct axis short-circuit sub-transient time constant.
Quadrature axis synchronous reactance
Quadrature axis sub-transient reactance
Quadrature axis short-circuit sub-transient time constant.
Stator time constant
Stator leakage reactance
Armature winding direct-current resistance.
Note: The above data item relating to armature winding direct-current resistance
need only be supplied with respect to Generating Units commissioned after 1st
March 1996 and in cases where, for whatever reason, the Generator or the
Network Operator, as the case may be is aware of the value of the relevant
parameter.
*
Turbogenerator inertia constant (MWsec/MVA)
Rated field current (amps) at Rated MW and MVAr output and at rated terminal
voltage.
Field current (amps) open circuit saturation curve for Generating Unit terminal
voltages ranging from 50% to 120% of rated value in 10% steps as derived from
appropriate manufacturers test certificates.
(b) Parameters for Generating Unit Step-up Transformers
*
Rated MVA
Voltage ratio
*
Positive sequence reactance (at max, min, & nominal tap)
Positive sequence resistance (at max, min, & nominal tap)
Zero phase sequence reactance
Tap changer range
Tap changer step size
Tap changer type: on load or off circuit
(c) Excitation Control System parameters
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Note: The data items requested under Option 1 below may continue to be provided in
relation to Generating Units on the System at 09 January 1995 (in this paragraph, the
"relevant date") or the new data items set out under Option 2 may be provided. Generators
or Network Operators, as the case may be, must supply the data as set out under Option 2
(and not those under Option 1) for Generating Unit excitation control systems
commissioned after the relevant date, those Generating Unit excitation control systems
recommissioned for any reason such as refurbishment after the relevant date and
Generating Unit excitation control systems where, as a result of testing or other process,
the Generator or Network Operator, as the case may be, is aware of the data items listed
under Option 2 in relation to that Generating Unit.
Option 1
DC gain of Excitation Loop
Rated field voltage
Maximum field voltage
Minimum field voltage
Maximum rate of change of field voltage (rising)
Maximum rate of change of field voltage (falling)
Details of Excitation Loop described in block diagram form showing transfer functions
of individual elements.
Dynamic characteristics of Over-excitation Limiter.
Dynamic characteristics of Under-excitation Limiter
Option 2
Excitation System Nominal Response
Rated Field Voltage
No-Load Field Voltage
Excitation System On-Load Positive Ceiling Voltage
Excitation System No-Load Positive Ceiling Voltage
Excitation System No-Load Negative Ceiling Voltage
Details of Excitation System (including PSS if fitted) described in block diagram form
showing transfer functions of individual elements.
Details of Over-excitation Limiter described in block diagram form showing transfer
functions of individual elements.
Details of Under-excitation Limiter described in block diagram form showing transfer
functions of individual elements.
The block diagrams submitted after 1 January 2009 in respect of the Excitation
System (including the Over-excitation Limiter and the Under-excitation Limiter) for
Generating Units with a Completion date after 1 January 2009 or subject to a
Modification to the Excitation System after 1 January 2009, should have been
verified as far as reasonably practicable by simulation studies as representing the
expected behaviour of the system.
(d) Governor Parameters
Incremental Droop values (in %) are required for each Generating Unit at six MW loading
points (MLP1 to MLP6) as detailed in PC.A.5.5.1 (this data item needs only be provided for
Large Power Stations)
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Note: The data items requested under Option 1 below may continue to be provided by
Generators in relation to Generating Units on the System at 09 January 1995 (in this
paragraph, the "relevant date") or they may provide the new data items set out under Option
2. Generators must supply the data as set out under Option 2 (and not those under Option
1) for Generating Unit governor control systems commissioned after the relevant date,
those Generating Unit governor control systems recommissioned for any reason such as
refurbishment after the relevant date and Generating Unit governor control systems where,
as a result of testing or other process, the Generator is aware of the data items listed under
Option 2 in relation to that Generating Unit.
Option 1
(i)
Governor Parameters (for Reheat Steam Units)
HP governor average gain MW/Hz
Speeder motor setting range
HP governor valve time constant
HP governor valve opening limits
HP governor valve rate limits
Reheater time constant (Active Energy stored in reheater)
IP governor average gain MW/Hz
IP governor setting range
IP governor valve time constant
IP governor valve opening limits
IP governor valve rate limits
Details of acceleration sensitive elements in HP & IP governor loop.
A governor block diagram showing transfer functions of individual elements.
(ii)
Governor Parameters (for Non-Reheat Steam Units and Gas Turbine Units)
Governor average gain
Speeder motor setting range
Time constant of steam or fuel governor valve
Governor valve opening limits
Governor valve rate limits
Time constant of turbine
Governor block diagram
The following data items need only be supplied for Large Power Stations:
(iii) Boiler & Steam Turbine Data
Boiler Time Constant (Stored Active Energy)
s
HP turbine response ratio:
proportion of Primary Response arising from HP turbine
%
HP turbine response ratio:
proportion of High Frequency Response arising from HP turbine
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[End of Option 1]
Option 2
(i)
Governor and associated prime mover Parameters - All Generating Units
Governor Block Diagram showing transfer function of individual elements including
acceleration sensitive elements.
Governor Time Constant (in seconds)
Speeder Motor Setting Range (%)
Average Gain (MW/Hz)
Governor Deadband (this data item need only be provided for Large Power
Stations)
- Maximum Setting
Hz
- Normal Setting
Hz
- Minimum Setting
Hz
Where the Generating Unit governor does not have a selectable deadband
facility, then the actual value of the deadband need only be provided.
The block diagrams submitted after 1 January 2009 in respect of the Governor
system for Generating Units with a Completion date after 1 January 2009 or
subject to a Modification to the governor system after 1 January 2009, should
have been verified as far as reasonably practicable by simulation studies as
representing the expected behaviour of the system.
(ii)
Governor and associated prime mover Parameters - Steam Units
HP Valve Time Constant (in seconds)
HP Valve Opening Limits (%)
HP Valve Opening Rate Limits (%/second)
HP Valve Closing Rate Limits (%/second)
HP Turbine Time Constant (in seconds)
IP Valve Time Constant (in seconds)
IP Valve Opening Limits (%)
IP Valve Opening Rate Limits (%/second)
IP Valve Closing Rate Limits (%/second)
IP Turbine Time Constant (in seconds)
LP Valve Time Constant (in seconds)
LP Valve Opening Limits (%)
LP Valve Opening Rate Limits (%/second)
LP Valve Closing Rate Limits (%/second)
LP Turbine Time Constant (in seconds)
Reheater Time Constant (in seconds)
Boiler Time Constant (in seconds)
HP Power Fraction (%)
IP Power Fraction (%)
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(iii) Governor and associated prime mover Parameters - Gas Turbine Units
Inlet Guide Vane Time Constant (in seconds)
Inlet Guide Vane Opening Limits (%)
Inlet Guide Vane Opening Rate Limits (%/second)
Inlet Guide Vane Closing Rate Limits (%/second)
Fuel Valve Constant (in seconds)
Fuel Valve Opening Limits (%)
Fuel Valve Opening Rate Limits (%/second)
Fuel Valve Closing Rate Limits (%/second)
Waste Heat Recovery Boiler Time Constant (in seconds)
(iv) Governor and associated prime mover Parameters - Hydro Generating Units
Guide Vane Actuator Time Constant (in seconds)
Guide Vane Opening Limits (%)
Guide Vane Opening Rate Limits (%/second)
Guide Vane Closing Rate Limits (%/second)
Water Time Constant (in seconds)
[End of Option 2]
(e) Unit Control Options
The following data items need only be supplied with respect to Large Power Stations:
Maximum Droop
%
Normal Droop
%
Minimum Droop
%
Maximum Frequency deadband
Hz
Normal Frequency deadband
Hz
Minimum Frequency deadband
Hz
Maximum output deadband
MW
Normal output deadband
MW
Minimum output deadband
MW
Frequency settings between which Unit Load Controller Droop applies:
- Maximum
Hz
- Normal
Hz
- Minimum
Hz
State if sustained response is normally selected.
(f)
Plant Flexibility Performance
The following data items need only be supplied with respect to Large Power Stations, and
should be provided with respect to each Genset:
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#
Run-up rate to Registered Capacity,
#
Run-down rate from Registered Capacity,
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#
Synchronising Generation,
Regulating range
Load rejection capability while still Synchronised and able to supply Load.
Data items marked with a hash (#) should be applicable to a Genset which has been
Shutdown for 48 hours.
*
Data items marked with an asterisk are already requested under partx1, PC.A.3.3.1, to
facilitate an early assessment by NGET as to whether detailed stability studies will be
required before an offer of terms for a CUSC Contract can be made. Such data items have
been repeated here merely for completeness and need not, of course, be resubmitted
unless their values, known or estimated, have changed.
(g) Generating Unit Mechanical Parameters
It is occasionally necessary for NGET to assess the interaction between the Total System
and the mechanical components of Generating Units. For Generating Units with a
Completion Date on or after 01 April 2015, the following data items should be supplied:
The number of turbine generator masses.
Diagram showing the Inertia and parameters for each turbine generator mass (kgm 2)
and Stiffness constants and parameters between each turbine generator mass for the
complete drive train (Nm/rad).
Number of poles.
Relative power applied to different parts of the turbine (%).
Torsional mode frequencies (Hz).
Modal damping decrement factors for the different mechanical modes.
PC.A.5.4
Non-Synchronous Generating Unit and Associated Control System Data
PC.A.5.4.1
The data submitted below are not intended to constrain any Ancillary Services Agreement
PC.A.5.4.2
The following Power Park Unit, Power Park Module and Power Station data should be supplied
in the case of a Power Park Module not connected to the Total System by a DC Converter (and
in the case of PC.A.5.4.2(f) any OTSUA):
Where a Manufacturer’s Data & Performance Report exists in respect of the model of the
Power Park Unit, the User may subject to NGET’s agreement, opt to reference the
Manufacturer’s Data & Performance Report as an alternative to the provision of data in
accordance with PC.A.5.4.2 except for:
(1) the section marked thus # at sub paragraph (b); and
(2) all of the harmonic and flicker parameters required under sub paragraph (h); and
(3) all of the site specific model parameters relating to the voltage or frequency control systems
required under sub paragraphs (d) and (e),
which must be provided by the User in addition to the Manufacturer’s Data & Performance
Report reference.
(a) Power Park Unit model
A mathematical model of each type of Power Park Unit capable of representing its transient
and dynamic behaviour under both small and large disturbance conditions. The model shall
include non-linear effects and represent all equipment relevant to the dynamic performance
of the Power Park Unit as agreed with NGET. The model shall be suitable for the study of
balanced, root mean square, positive phase sequence time-domain behaviour, excluding the
effects of electromagnetic transients, harmonic and sub-harmonic frequencies.
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The model shall accurately represent the overall performance of the Power Park Unit over
its entire operating range including that which is inherent to the Power Park Unit and that
which is achieved by use of supplementary control systems providing either continuous or
stepwise control. Model resolution should be sufficient to accurately represent Power Park
Unit behaviour both in response to operation of Transmission System protection and in the
context of longer-term simulations.
The overall structure of the model shall include:
(i)
any supplementary control signal modules not covered by (c), (d) and (e) below.
(ii)
any blocking, deblocking and protective trip features that are part of the Power Park Unit
(e.g. “crowbar”).
(iii) any other information required to model the Power Park Unit behaviour to meet the model
functional requirement described above.
The model shall be submitted in the form of a transfer function block diagram and may be
accompanied by dynamic and algebraic equations.
This model shall display all the transfer functions and their parameter values, any non wind-up
logic, signal limits and non-linearities.
The submitted Power Park Unit model and the supplementary control signal module models
covered by (c), (d) and (e) below shall have been validated and this shall be confirmed by the
Generator. The validation shall be based on comparing the submitted model simulation results
against measured test results. Validation evidence shall also be submitted and this shall include
the simulation and measured test results. The latter shall include appropriate short-circuit tests.
In the case of an Embedded Medium Power Station not subject to a Bilateral Agreement the
Network Operator will provide NGET with the validation evidence if requested by NGET. The
validation of the supplementary control signal module models covered by (c), (d) and (e) below
applies only to a Power Park Module with a Completion Date after 1 January 2009.
(b) Power Park Unit parameters
*
Rated MVA
*
Rated MW
*
Rated terminal voltage
*
Average site air density (kg/m3), maximum site air density (kg/m3) and minimum site air
density (kg/m3) for the year
Year for which the air density is submitted
Number of pole pairs
Blade swept area (m2)
Gear box ratio
Mechanical drive train
For each Power Park Unit, details of the parameters of the drive train represented as
an equivalent two mass model should be provided. This model should accurately
represent the behaviour of the complete drive train for the purposes of power system
analysis studies and should include the following data items:Equivalent inertia constant (MWsec/MVA) of the first mass (e.g. wind turbine rotor
and blades) at minimum, synchronous and rated speeds
Equivalent inertia constant (MWsec/MVA) of the second mass (e.g. generator
rotor) at minimum, synchronous and rated speeds
Equivalent shaft stiffness between the two masses (Nm/electrical radian)
Additionally, for Power Park Units that are induction generators (e.g. squirrel cage,
doubly-fed) driven by wind turbines:
* Stator resistance
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* Stator reactance
* Magnetising reactance.
* Rotor resistance.(at starting)
* Rotor resistance.(at rated running)
* Rotor reactance (at starting)
* Rotor reactance (at rated running)
Additionally for doubly-fed induction generators only:
The generator rotor speed range (minimum and maximum speeds in RPM)
The optimum generator rotor speed versus wind speed submitted in tabular format
Power converter rating (MVA)
The rotor power coefficient (Cp) versus tip speed ratio () curves for a range of blade
angles (where applicable) together with the corresponding values submitted in tabular
format. The tip speed ratio () is defined as R/U where  is the angular velocity of
the rotor, R is the radius of the wind turbine rotor and U is the wind speed.
The electrical power output versus generator rotor speed for a range of wind speeds
over the entire operating range of the Power Park Unit, together with the
corresponding values submitted in tabular format.
The blade angle versus wind speed curve together with the corresponding values
submitted in tabular format.
The electrical power output versus wind speed over the entire operating range of the
Power Park Unit, together with the corresponding values submitted in tabular format.
Transfer function block diagram, including parameters and description of the operation
of the power electronic converter and fault ride through capability (where applicable).
For a Power Park Unit consisting of a synchronous machine in combination with a back to
back DC Converter, or for a Power Park Unit not driven by a wind turbine, the data to be
supplied shall be agreed with NGET in accordance with PC.A.7.
(c) Torque / speed and blade angle control systems and parameters
For the Power Park Unit, details of the torque / speed controller and blade angle controller
in the case of a wind turbine and power limitation functions (where applicable) described in
block diagram form showing transfer functions and parameters of individual elements.
(d) Voltage/Reactive Power/Power Factor control system parameters
For the Power Park Unit and Power Park Module details of voltage/Reactive
Power/Power Factor controller (and PSS if fitted) described in block diagram form showing
transfer functions and parameters of individual elements.
(e) Frequency control system parameters
For the Power Park Unit and Power Park Module details of the Frequency controller
described in block diagram form showing transfer functions and parameters of individual
elements.
(f)
Protection
Details of settings for the following Protection relays (to include): Under Frequency, over
Frequency, under voltage, over voltage, rotor over current, stator over current, high wind
speed shut down level.
(g) Complete Power Park Unit model, parameters and controls
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An alternative to PC.A.5.4.2 (a), (b), (c), (d), (e) and (f), is the submission of a single
complete model that consists of the full information required under PC.A.5.4.2 (a), (b), (c),
(d), (e) and (f) provided that all the information required under PC.A.5.4.2 (a), (b), (c), (d), (e)
and (f) individually is clearly identifiable.
(h) Harmonic and flicker parameters
When connecting a Power Park Module, it is necessary for NGET to evaluate the
production of flicker and harmonics on NGET and User's Systems. At NGET's reasonable
request, the User (a Network Operator in the case of an Embedded Power Park Module
not subject to a Bilateral Agreement) is required to submit the following data (as defined in
IEC 61400-21 (2001)) for each Power Park Unit:Flicker coefficient for continuous operation.
Flicker step factor.
Number of switching operations in a 10 minute window.
Number of switching operations in a 2 hour window.
Voltage change factor.
Current Injection at each harmonic for each Power Park Unit and for each Power Park
Module
* Data items marked with an asterisk are already requested under part 1, PC.A.3.3.1, to
facilitate an early assessment by NGET as to whether detailed stability studies will be
required before an offer of terms for a CUSC Contract can be made. Such data items have
been repeated here merely for completeness and need not, of course, be resubmitted
unless their values, known or estimated, have changed.
PC.A.5.4.3
DC Converter
PC.A.5.4.3.1
For a DC Converter at a DC Converter Station or a Power Park Module connected to the Total
System by a DC Converter (or in the case of OTSUA which includes an OTSDUW DC
Converter) the following information for each DC Converter and DC Network should be
supplied:
(a) DC Converter parameters
*
Rated MW per pole for transfer in each direction;
*
DC Converter type (i.e. current or voltage source);
*
Number of poles and pole arrangement;
*
Rated DC voltage/pole (kV);
*
Return path arrangement;
(b) DC Converter transformer parameters
Rated MVA
Nominal primary voltage (kV);
Nominal secondary (converter-side) voltage(s) (kV);
Winding and earthing arrangement;
Positive phase sequence reactance at minimum, maximum and nominal tap;
Positive phase sequence resistance at minimum, maximum and nominal tap;
Zero phase sequence reactance;
Tap-changer range in %;
number of tap-changer steps;
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(c) DC Network parameters
Rated DC voltage per pole;
Rated DC current per pole;
Single line diagram of the complete DC Network;
Details of the complete DC Network, including resistance, inductance and capacitance
of all DC cables and/or DC lines;
Details of any DC reactors (including DC reactor resistance), DC capacitors and/or DCside filters that form part of the DC Network;
(d) AC filter reactive compensation equipment parameters
Note: The data provided pursuant to this paragraph must not include any contribution from
reactive compensation plant owned or operated by NGET.
Total number of AC filter banks.
Type of equipment (e.g. fixed or variable)
Single line diagram of filter arrangement and connections;
Reactive Power rating for each AC filter bank, capacitor bank or operating range of
each item of reactive compensation equipment, at rated voltage;
Performance chart showing Reactive Power capability of the DC Converter, as a
function of MW transfer, with all filters and reactive compensation plant, belonging to
the DC Converter Station working correctly.
Note: Details in PC.A.5.4.3.1 are required for each DC Converter connected to the DC Network,
unless each is identical or where the data has already been submitted for an identical DC
Converter at another Connection Point.
Note: For a Power Park Module connected to the Grid Entry point or (User System Entry
Point if Embedded) by a DC Converter the equivalent inertia and fault infeed at the Power Park
Unit should be given.
DC Converter Control System Models
PC.A.5.4.3.2
The following data is required by NGET to represent DC Converters and associated DC
Networks (and including OTSUA which includes an OTSDUW DC Converter) in dynamic power
system simulations, in which the AC power system is typically represented by a positive
sequence equivalent. DC Converters are represented by simplified equations and are not
modelled to switching device level.
(i)
Static VDC-IDC (DC voltage - DC current) characteristics, for both the rectifier and inverter
modes for a current source converter. Static VDC-PDC (DC voltage - DC power)
characteristics, for both the rectifier and inverter modes for a voltage source converter.
Transfer function block diagram including parameters representation of the control systems
of each DC Converter and of the DC Converter Station, for both the rectifier and inverter
modes. A suitable model would feature the DC Converter firing angle as the output variable.
(ii)
Transfer function block diagram representation including parameters of the DC Converter
transformer tap changer control systems, including time delays
(iii) Transfer function block diagram representation including
parameters of AC filter and
reactive compensation equipment control systems, including any time delays.
(iv) Transfer function block diagram representation including parameters of any Frequency
and/or load control systems.
(v) Transfer function block diagram representation including parameters of any small signal
modulation controls such as power oscillation damping controls or sub-synchronous
oscillation damping controls, that have not been submitted as part of the above control
system data.
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(vi) Transfer block diagram representation of the Reactive Power control at converter ends for a
voltage source converter.
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Plant Flexibility Performance
PC.A.5.4.3.3
The following information on plant flexibility and performance should be supplied (and also in
respect of OTSUA which includes an OTSDUW DC Converter):
(i)
Nominal and maximum (emergency) loading rate with the DC Converter in rectifier mode.
(ii)
Nominal and maximum (emergency) loading rate with the DC Converter in inverter mode.
(iii) Maximum recovery time, to 90% of pre-fault loading, following an AC system fault or severe
voltage depression.
(iv) Maximum recovery time, to 90% of pre-fault loading, following a transient DC Network fault.
Harmonic Assessment Information
PC.A.5.4.3.4
DC Converter owners shall provide such additional further information as required by NGET in
order that compliance with CC.6.1.5 can be demonstrated.
* Data items marked with an asterisk are already requested under part 1, PC.A.3.3.1, to facilitate
an early assessment by NGET as to whether detailed stability studies will be required before an
offer of terms for a CUSC Contract can be made. Such data items have been repeated here
merely for completeness and need not, of course, be resubmitted unless their values, known or
estimated, have changed.
PC.A.5.5
Response Data For Frequency Changes
The information detailed below is required to describe the actual frequency response capability
profile as illustrated in Figure CC.A.3.1 of the Connection Conditions, and need only be
provided for each:
(i)
Genset at Large Power Stations; and
(ii)
Generating Unit, Power Park Module or CCGT Module at a Medium Power Station or DC
Converter Station that has agreed to provide Frequency response in accordance with a
CUSC Contract.
In the case of (ii) above for the rest of this PC.A.5.5 where reference is made to Gensets, it
shall include such Generating Units, CCGT Modules, Power Park Modules and DC
Converters as appropriate, but excludes OTSDUW Plant and Apparatus utilising
OTSDUW DC Converters.
In this PC.A.5.5, for a CCGT Module with more than one Generating Unit, the phrase Minimum
Generation applies to the entire CCGT Module operating with all Generating Units
Synchronised to the System. Similarly for a Power Park Module with more than one Power
Park Unit, the phrase Minimum Generation applies to the entire Power Park Module operating
with all Power Park Units Synchronised to the System.
PC.A.5.5.1
MW Loading Points At Which Data Is Required
Response values are required at six MW loading points (MLP1 to MLP6) for each Genset.
Primary and Secondary Response values need not be provided for MW loading points which
are below Minimum Generation. MLP1 to MLP6 must be provided to the nearest MW.
Prior to the Genset being first Synchronised, the MW loading points must take the following
values :
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MLP1
Designed Minimum Operating Level
MLP2
Minimum Generation
MLP3
70% of Registered Capacity
MLP4
80% of Registered Capacity
MLP5
95% of Registered Capacity
MLP6
Registered Capacity
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When data is provided after the Genset is first Synchronised, the MW loading points may take
any value between Designed Minimum Operating Level and Registered Capacity but the value
of the Designed Minimum Operating Level must still be provided if it does not form one of the
MW loading points.
PC.A.5.5.2
Primary And Secondary Response To Frequency Fall
Primary and Secondary Response values for a -0.5Hz ramp are required at six MW loading
points (MLP1 to MLP6) as detailed above
PC.A.5.5.3
High Frequency Response To Frequency Rise
High Frequency Response values for a +0.5Hz ramp are required at six MW loading points
(MLP1 to MLP6) as detailed above.
PC.A.5.6
Mothballed Generating Unit Mothballed Power Park Module Or Mothballed DC Converter At A DC
Converter Station And Alternative Fuel Information
Data identified under this section PC.A.5.6 must be submitted as required under PC.A.1.2 and at
NGET’s reasonable request.
In the case of Embedded Medium Power Stations not subject to a Bilateral Agreement and
Embedded DC Converter Stations not subject to a Bilateral Agreement, upon request from
NGET each Network Operator shall provide the information required in PC.A.5.6.1, PC.A.5.6.2,
PC.A.5.6.3 and PC.A.5.6.4 on respect of such Embedded Medium Power Stations and
Embedded DC Converters Stations with their System.
PC.A.5.6.1
Mothballed Generating Unit Information
Generators and DC Converter Station owners must supply with respect to each Mothballed
Generating Unit, Mothballed Power Park Module or Mothballed DC Converter at a DC
Converter Station the estimated MW output which could be returned to service within the
following time periods from the time that a decision to return was made:
< 1 month;
1-2 months;
2-3 months;
3-6 months;
6-12 months; and
>12 months.
The return to service time should be determined in accordance with Good Industry Practice
assuming normal working arrangements and normal plant procurement lead times. The MW
output values should be the incremental values made available in each time period as further
described in the DRC.
PC.A.5.6.2
Generators and DC Converter Station owners must also notify NGET of any significant factors
which may prevent the Mothballed Generating Unit, Mothballed Power Park Module or
Mothballed DC Converter at a DC Converter Station achieving the estimated values provided
under PC.A.5.6.1 above, excluding factors relating to Transmission Entry Capacity.
PC.A.5.6.3
Alternative Fuel Information
The following data items must be supplied with respect to each Generating Unit whose main fuel
is gas.
For each alternative fuel type (if facility installed):
(a) Alternative fuel type e.g. oil distillate, alternative gas supply
(b) For the changeover from main to alternative fuel:
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Time to carry out off-line and on-line fuel changeover (minutes).
-
Maximum output following off-line and on-line changeover (MW).
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-
Maximum output during on-line fuel changeover (MW).
-
Maximum operating time at full load assuming typical and maximum possible stock
levels (hours).
-
Maximum rate of replacement of depleted stocks (MWh electrical/day) on the basis of
Good Industry Practice.
-
Is changeover to alternative fuel used in normal operating arrangements?
-
Number of successful changeovers carried out in the last NGET Financial Year
(choice of 0, 1-5, 6-10, 11-20, >20).
(c) For the changeover back to main fuel:
-
Time to carry out off-line and on-line fuel changeover (minutes).
-
Maximum output during on-line fuel changeover (MW).
PC.A.5.6.4
Generators must also notify NGET of any significant factors and their effects which may prevent
the use of alternative fuels achieving the estimated values provided under PC.A.5.6.3 above (e.g.
emissions limits, distilled water stocks etc.)
PC.A.5.7
Black Start Related Information
Data identified under this section PC.A.5.7 must be submitted as required under PC.A.1.2. This
information may also be requested by NGET during a Black Start and should be provided by
Generators where reasonably possible. Generators in this section PC.A.5.7 means Generators
only in respect of their Large Power Stations.
The following data items/text must be supplied, from each Generator to NGET, with respect to
each BM Unit at a Large Power Station (excluding the Generating Units that are contracted to
provide Black Start Capability, Power Park Modules or Generating Units with an Intermittent
Power Source);
(a) Expected time for each BM Unit to be Synchronised following a Total Shutdown or Partial
Shutdown. The assessment should include the Power Station’s ability to re-synchronise
all BM Units, if all were running immediately prior to the Total Shutdown or Partial
Shutdown. Additionally this should highlight any specific issues (i.e. those that would
impact on the BM Unit’s time to be Synchronised) that may arise, as time progresses
without external supplies being restored.
(b) Block Loading Capability. This should be provided in either graphical or tabular format
showing the estimated block loading capability from 0MW to Registered Capacity. Any
particular ‘hold’ points should also be identified. The data of each BM Unit should be
provided for the condition of a ‘hot’ unit that was Synchronised just prior to the Total
Shutdown or Partial Shutdown and also for the condition of a ‘cold’ unit. The block loading
assessment should be done against a frequency variation of 49.5Hz – 50.5Hz.
PC.A.6
USERS' SYSTEM DATA
PC.A.6.1
Introduction
PC.A.6.1.1
Each User, whether connected directly via an existing Connection Point to the National
Electricity Transmission System or seeking such a direct connection, or providing terms for
connection of an Offshore Transmission System to its User System to NGET or undertaking
OTSDUW, shall provide NGET with data on its User System or OTSDUW Plant and Apparatus
which relates to the Connection Site containing the Connection Point (or Interface Points or
Connection Points in the case of OTSUA) both current and forecast, as specified in PC.A.6.2 to
PC.A.6.6.
PC.A.6.1.2
Each User must reflect the system effect at the Connection Site(s) of any third party Embedded
within its User System whether existing or proposed.
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PC.A.6.1.3
PC.A.6.2, and PC.A.6.4 to PC.A.6.6 consist of data which is only to be supplied to NGET at
NGET’s reasonable request. In the event that NGET identifies a reason for requiring this data,
NGET shall write to the relevant User(s), requesting the data, and explaining the reasons for the
request. If the User(s) wishes, NGET shall also arrange a meeting at which the request for data
can be discussed, with the objective of identifying the best way in which NGET’s requirements
can be met.
PC.A.6.2
Transient Overvoltage Assessment Data
PC.A.6.2.1
It is occasionally necessary for NGET to undertake transient overvoltage assessments (e.g.
capacitor switching transients, switchgear transient recovery voltages, etc). At NGET’s
reasonable request, each User is required to provide the following data with respect to the
Connection Site (and in the case of OTSUA, Interface Points and Connection Points), current
and forecast, together with a Single Line Diagram where not already supplied under PC.A.2.2.1,
as follows:
(a) busbar layout plan(s), including dimensions and geometry showing positioning of any current
and voltage transformers, through bushings, support insulators, disconnectors, circuit
breakers, surge arresters, etc. Electrical parameters of any associated current and voltage
transformers, stray capacitances of wall bushings and support insulators, and grading
capacitances of circuit breakers;
(b) Electrical parameters and physical construction details of lines and cables connected at that
busbar. Electrical parameters of all plant e.g., transformers (including neutral earthing
impedance or zig-zag transformers, if any), series reactors and shunt compensation
equipment connected at that busbar (or to the tertiary of a transformer) or by lines or cables
to that busbar;
(c) Basic insulation levels (BIL) of all Apparatus connected directly, by lines or by cables to the
busbar;
(d) characteristics of overvoltage Protection devices at the busbar and at the termination points
of all lines, and all cables connected to the busbar;
(e) fault levels at the lower voltage terminals of each transformer connected directly or indirectly
to the National Electricity Transmission System (including OTSUA at each Interface
Point and Connection Point) without intermediate transformation;
(f)
the following data is required on all transformers operating at Supergrid Voltage throughout
Great Britain and, in Scotland and Offshore, also at 132kV (including OTSUA): three or five
limb cores or single phase units to be specified, and operating peak flux density at nominal
voltage;
(g) an indication of which items of equipment may be out of service simultaneously during
Planned Outage conditions.
PC.A.6.3
User's Protection Data
PC.A.6.3.1
Protection
The following information is required which relates only to Protection equipment which can trip or
inter-trip or close any Connection Point circuit-breaker or any Transmission circuit-breaker (or
in the case of OTSUA, any Interface Point or Connection Point circuit breaker). This
information need only be supplied once, in accordance with the timing requirements set out in
PC.A.1.4(b), and need not be supplied on a routine annual basis thereafter, although NGET
should be notified if any of the information changes
(a) a full description, including estimated settings, for all relays and Protection systems
installed or to be installed on the User's System;
(b) a full description of any auto-reclose facilities installed or to be installed on the User's
System, including type and time delays;
(c) a full description, including estimated settings, for all relays and Protection systems or to be
installed on the generator, generator transformer, Station Transformer and their associated
connections;
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(d) for Generating Units (other than Power Park Units) or Power Park Modules or DC
Converters at a DC Converter Station or OTSDUW Plant and Apparatus having (or
intended to have) a circuit breaker at the generator terminal voltage, clearance times for
electrical faults within the Generating Unit (other than a Power Park Unit) or Power Park
Module zone, or within the OTSDUW Plant and Apparatus;
(e) the most probable fault clearance time for electrical faults on any part of the User's System
directly connected to the National Electricity Transmission System including OTSDUW
Plant and Apparatus; and
(f)
in the case of OTSDUW Plant and Apparatus, synchronisation facilities and delayed auto
reclose sequence schedules (where applicable).
PC.A.6.4
Harmonic Studies
PC.A.6.4.1
It is occasionally necessary for NGET to evaluate the production/magnification of harmonic
distortion on NGET and User’s Systems (and OTSUA), especially when NGET is connecting
equipment such as capacitor banks. At NGET’s reasonable request, each User is required to
submit data with respect to the Connection Site (and in the case of OTSUA, each Interface
Point and Connection Point), current and forecast, and where not already supplied under
PC.A.2.2.4 and PC.A.2.2.5, as follows:
PC.A.6.4.2
Overhead lines and underground cable circuits of the User's Subtransmission System must be
differentiated and the following data provided separately for each type:
Positive phase sequence resistance;
Positive phase sequence reactance;
Positive phase sequence susceptance;
and for all transformers connecting the User's Subtransmission System and OTSDUW Plant
and Apparatus to a lower voltage:
Rated MVA;
Voltage Ratio;
Positive phase sequence resistance;
Positive phase sequence reactance;
and at the lower voltage points of those connecting transformers:
Equivalent positive phase sequence susceptance;
Connection voltage and MVAr rating of any capacitor bank and component design
parameters if configured as a filter;
Equivalent positive phase sequence interconnection impedance with other lower voltage
points;
The minimum and maximum Demand (both MW and MVAr) that could occur;
Harmonic current injection sources in Amps at the Connection voltage points. Where the
harmonic injection current comes from a diverse group of sources, the equivalent
contribution may be established from appropriate measurements;
Details of traction loads, eg connection phase pairs, continuous variation with time, etc;
An indication of which items of equipment may be out of service simultaneously during
Planned Outage conditions.
PC.A.6.5
Voltage Assessment Studies
It is occasionally necessary for NGET to undertake detailed voltage assessment studies (e.g., to
examine potential voltage instability, voltage control co-ordination or to calculate voltage step
changes). At NGET’s reasonable request, each User is required to submit the following data
where not already supplied under PC.A.2.2.4 and PC.A.2.2.5:
For all circuits of the User’s Subtransmission System (and any OTSUA):-
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Positive Phase Sequence Reactance;
Positive Phase Sequence Resistance;
Positive Phase Sequence Susceptance;
MVAr rating of any reactive compensation equipment;
and for all transformers connecting the User's Subtransmission System to a lower voltage (and
any OTSUA):
Rated MVA;
Voltage Ratio;
Positive phase sequence resistance;
Positive Phase sequence reactance;
Tap-changer range;
Number of tap steps;
Tap-changer type: on-load or off-circuit;
AVC/tap-changer time delay to first tap movement;
AVC/tap-changer inter-tap time delay;
and at the lower voltage points of those connecting transformers (and any OTSUA):Equivalent positive phase sequence susceptance;
MVAr rating of any reactive compensation equipment;
Equivalent positive phase sequence interconnection impedance with other lower voltage
points;
The maximum Demand (both MW and MVAr) that could occur;
Estimate of voltage insensitive (constant power) load content in % of total load at both
winter peak and 75% off-peak load conditions.
PC.A.6.6
Short Circuit Analysis
PC.A.6.6.1
Where prospective short-circuit currents on equipment owned, operated or managed by NGET
are greater than 90% of the equipment rating, and in NGET’s reasonable opinion more accurate
calculations of short-circuit currents are required, then at NGET’s request each User is required
to submit data with respect to the Connection Site (and in the case of OTSUA, each Interface
Point and Connection Point), current and forecast, and where not already supplied under
PC.A.2.2.4 and PC.A.2.2.5, as follows:
PC.A.6.6.2
For all circuits of the User’s Subtransmission System (and any OTSUA):
Positive phase sequence resistance;
Positive phase sequence reactance;
Positive phase sequence susceptance;
Zero phase sequence resistance (both self and mutuals);
Zero phase sequence reactance (both self and mutuals);
Zero phase sequence susceptance (both self and mutuals);
and for all transformers connecting the User's Subtransmission System to a lower voltage (and
any OTSUA):
Rated MVA;
Voltage Ratio;
Positive phase sequence resistance (at max, min and nominal tap);
Positive Phase sequence reactance (at max, min and nominal tap);
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Zero phase sequence reactance (at nominal tap);
Tap changer range;
Earthing method: direct, resistance or reactance;
Impedance if not directly earthed;
and at the lower voltage points of those connecting transformers (and any OTSUA):
The maximum Demand (in MW and MVAr) that could occur;
Short-circuit infeed data in accordance with PC.A.2.5.6 unless the User’s lower voltage
network runs in parallel with the User’s Subtransmission System, when to prevent double
counting in each node infeed data, a  equivalent comprising the data items of PC.A.2.5.6
for each node together with the positive phase sequence interconnection impedance
between the nodes shall be submitted.
PC.A.7
ADDITIONAL DATA FOR NEW TYPES OF POWER STATIONS, DC CONVERTER STATIONS,
OTSUA AND CONFIGURATIONS
Notwithstanding the Standard Planning Data and Detailed Planning Data set out in this
Appendix, as new types of configurations and operating arrangements of Power Stations, DC
Converter Stations and OTSUA emerge in future, NGET may reasonably require additional data
to represent correctly the performance of such Plant and Apparatus on the System, where the
present data submissions would prove insufficient for the purpose of producing meaningful
System studies for the relevant parties.
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PART 3 - DETAILED PLANNING DATA
PC.A.8
To allow a User to model the National Electricity Transmission System, NGET will provide,
upon request, the following Network Data to Users, calculated in accordance with Good
Industry Practice:
To allow a User to assess undertaking OTSDUW and except where provided for in Appendix F,
NGET will provide upon request the following Network Data to Users, calculated in accordance
with Good Industry Practice:
PC.A.8.1
Single Point of Connection
For a Single Point of Connection to a User's System (and OTSUA), as an equivalent 400kV or
275kV source and also in Scotland and Offshore as an equivalent 132kV source, the data (as at
the HV side of the Point of Connection (and in the case of OTSUA, each Interface Point and
Connection Point) reflecting data given to NGET by Users) will be given to a User as follows:
The data items listed under the following parts of PC.A.8.3:
(a) (i), (ii), (iii), (iv), (v) and (vi)
and the data items shall be provided in accordance with the detailed provisions of PC.A.8.3 (b) (e).
PC.A.8.2
Multiple Point of Connection
For a Multiple Point of Connection to a User's System equivalents suitable for use in loadflow
and fault level analysis shall be provided. These equivalents will normally be in the form of a π
model or extension with a source (or demand for a loadflow equivalent) at each node and a
linking impedance. The boundary nodes for the equivalent shall be either at the Connection
Point (and in the case of OTSDUW, each Interface Point and Connection Point) or (where
NGET agrees) at suitable nodes (the nodes to be agreed with the User) within the National
Electricity Transmission System. The data at the Connection Point (and in the case of
OTSDUW, each Interface Point and Connection Point) will be given to a User as follows:
The data items listed under the following parts of PC.A.8.3:(a) (i), (ii), (iv), (v), (vi), (vii), (viii), (ix), (x) and (xi)
and the data items shall be provided in accordance with the detailed provisions of PC.A.8.3 (b) (e).
When an equivalent of this form is not required NGET will not provide the data items listed under
the following parts of PC.A.8.3:(a) (vii), (viii), (ix), (x) and (xi)
PC.A.8.3
Data Items
(a) The following is a list of data utilised in this part of the PC. It also contains rules on the data
which generally apply.
(i)
symmetrical three-phase short circuit current infeed at the instant of fault from the
National Electricity Transmission System, (I1");
(ii)
symmetrical three-phase short circuit current from the National Electricity
Transmission System after the subtransient fault current contribution has substantially
decayed, (I1');
(iii) the zero sequence source resistance and reactance values at the Point of Connection
(and in case of OTSUA, each Interface Point and Connection Point), consistent with
the maximum infeed below;
(iv) the pre-fault voltage magnitude at which the maximum fault currents were calculated;
(v)
the positive sequence X/R ratio at the instant of fault;
(vi) the negative sequence resistance and reactance values of the National Electricity
Transmission System seen from the (Point of Connection and in case of OTSUA,
each Interface Point and Connection Point), if substantially different from the values
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of positive sequence resistance and reactance which would be derived from the data
provided above;
(vii) the initial positive sequence resistance and reactance values of the two (or more)
sources and the linking impedance(s) derived from a fault study constituting the (π)
equivalent and evaluated without the User network and load and where appropriate
without elements of the National Electricity Transmission System between the User
network and agreed boundary nodes (and in case of OTSUA, each Interface Point and
Connection Point);
(viii) the positive sequence resistance and reactance values of the two (or more) sources
and the linking impendence(s) derived from a fault study, considering the short circuit
current contributions after the subtransient fault current contribution has substantially
decayed, constituting the (π) equivalent and evaluated without the User network and
load, and where appropriate without elements of the National Electricity
Transmission System between the User network and agreed boundary nodes (and in
case of OTSUA, each Interface Point and Connection Point);
(ix) the corresponding zero sequence impedance values of the (π) equivalent produced for
use in fault level analysis;
(x)
the Demand and voltage at the boundary nodes and the positive sequence resistance
and reactance values of the linking impedance(s) derived from a loadflow study
considering National Electricity Transmission System peak Demand constituting the
(π) loadflow equivalent; and,
(xi) where the agreed boundary nodes are not at a Connection Point (and in case of
OTSUA, Interface Point or Connection Point), the positive sequence and zero
sequence impedances of all elements of the National Electricity Transmission
System between the User network and agreed boundary nodes that are not included in
the equivalent (and in case of OTSUA, each Interface Point and Connection Point).
(b) To enable the model to be constructed, NGET will provide data based on the following
conditions.
(c) The initial symmetrical three phase short circuit current and the transient period three phase
short circuit current will normally be derived from the fixed impedance studies. The latter
value should be taken as applying at times of 120ms and longer. Shorter values may be
interpolated using a value for the subtransient time constant of 40ms. These fault currents
will be obtained from a full System study based on load flow analysis that takes into account
any existing flow across the point of connection being considered.
(d) Since the equivalent will be produced for the 400kV or 275kV and also in Scotland and
Offshore132kV parts of the National Electricity Transmission System NGET will provide
the appropriate supergrid transformer data.
(e) The positive sequence X/R ratio and the zero sequence impedance value will correspond to
the NGET source network only, that is with the section of network if any with which the
equivalent is to be used excluded. These impedance values will be derived from the
condition when all Generating Units are Synchronised to the National Electricity
Transmission System or a User's System and will take account of active sources only
including any contribution from the load to the fault current. The passive component of the
load itself or other system shunt impedances should not be included.
(f)
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A User may at any time, in writing, specifically request for an equivalent to be prepared for
an alternative System condition, for example where the User's System peak does not
correspond to the National Electricity Transmission System peak, and NGET will, insofar
as such request is reasonable, provide the information as soon as reasonably practicable
following the request.
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APPENDIX B - SINGLE LINE DIAGRAMS
PC.B.1
The diagrams below show three examples of single line diagrams, showing the detail that should
be incorporated in the diagram. The first example is for an Network Operator connection, the
second for a Generator connection, the third for a Power Park Module electrically equivalent
system.
Network Operator Single Line Diagram
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Generator Single Line Diagram
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Power Park Module Single Line Diagram
Notes:
(1) The electrically equivalent Power Park Unit consists of a number of actual Power Park
Units of the same type ie. any equipment external to the Power Park Unit terminals is
considered as part of the Equivalent Network. Power Park Units of different types shall be
included in separate electrically equivalent Power Park Units. The total number of
equivalent Power Park Units shall represent all of the actual Power Park Units in the
Power Park Module.
(2) Separate electrically equivalent networks are required for each different type of electrically
equivalent Power Park Unit. The electrically equivalent network shall include all equipment
between the Power Park Unit terminals and the Common Collection Busbar.
(3) All Plant and Apparatus including the circuit breakers, transformers, lines, cables and
reactive compensation plant between the Common Collection Busbar and Substation A
shall be shown.
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APPENDIX C - TECHNICAL AND DESIGN CRITERIA
PC.C.1
Planning and design of the SPT and SHETL Transmission Systems is based generally, but not
totally, on criteria which evolved from joint consultation among various Transmission Licensees
responsible for design of the National Electricity Transmission System.
PC.C.2
The above criteria are set down within the standards, memoranda, recommendations and reports
and are provided as a guide to system planning. It should be noted that each scheme for
reinforcement or modification of the Transmission System is individually designed in the light of
economic and technical factors associated with the particular system limitations under
consideration.
PC.C.3
The tables below identify the literature referred to above, together with the main topics
considered within each document.
PART 1 – SHETL's TECHNICAL AND DESIGN CRITERIA
ITEM No.
1
2
3
4
5
6
7
DOCUMENT
National Electricity Transmission System Security and Quality
of Supply Standard
System Phasing
Not used
Planning Limits for Voltage Fluctuations Caused by Industrial,
Commercial and Domestic Equipment in the United Kingdom
EHV or HV Supplies to Induction Furnaces
Voltage unbalance limits.
Harmonic current limits.
Planning Levels for Harmonic Voltage Distortion and the
Connection of Non-Linear Loads to Transmission Systems
and Public Electricity Supply Systems in the United Kingdom
Harmonic distortion (waveform).
Harmonic voltage distortion.
Harmonic current distortion.
Stage 1 limits.
Stage 2 limits.
Stage 3 Limits
Addition of Harmonics
Short Duration Harmonics
Site Measurements
AC Traction Supplies to British Rail
REFERENCE No.
Version [ ]
TPS 13/4
ER P28
ER P16
(Supported by
ACE Report
No.48)
ER G5/4
(Supported by
ACE Report
No.73)
ER P24
Type of supply point to railway system.
Estimation of traction loads.
Nature of traction current.
System disturbance estimation.
Earthing arrangements.
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ITEM No.
8
9
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DOCUMENT
Operational Memoranda
REFERENCE No.
(SOM)
Main System operating procedure.
SOM 1
Operational standards of security.
SOM 3
Voltage and reactive control on main system.
SOM 4
System warnings and procedures for instructed load
reduction.
SOM 7
Continuous tape recording of system control telephone
messages and instructions.
SOM 10
Emergency action in the event of an exceptionally
serious breakdown of the main system.
Planning Limits for Voltage Unbalance in the United Kingdom.
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ER P29
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PART 2 - SPT's TECHNICAL AND DESIGN CRITERIA
ITEM No.
1
2
3
4
5
6
7
DOCUMENT
National Electricity Transmission System Security and
Quality of Supply Standard
System Phasing
Not used
Planning Limits for Voltage Fluctuations Caused by
Industrial, Commercial and Domestic Equipment in the
United Kingdom
EHV or HV Supplies to Induction Furnaces
Voltage Unbalance limits.
Harmonic current limits.
Planning Levels for Harmonic Voltage Distortion and the
Connection of Non-Linear Loads to Transmission Systems
and Public Electricity Supply Systems in the United
Kingdom
Harmonic distortion (waveform).
Harmonic voltage distortion.
Harmonic current distortion.
Stage 1 limits.
Stage 2 limits.
Stage 3 Limits
Addition of Harmonics
Short Duration Harmonics
Site Measurements
AC Traction Supplies to British Rail
REFERENCE No.
Version [ ]
TDM 13/10,002
Issue 4
ER P28
ER P16
(Supported by
ACE Report
No.48)
ER G5/4
(Supported by
ACE Report
No.73)
ER P24
Type of supply point to railway system.
Estimation of traction loads.
Nature of traction current.
System disturbance estimation.
Earthing arrangements.
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APPENDIX D - DATA NOT DISCLOSED TO A RELEVANT
TRANSMISSION LICENSEE
PC.D.1
Pursuant to PC.3.4, NGET will not disclose to a Relevant Transmission Licensee data items
specified in the below extract:
PC
REFERENCE
DATA DESCRIPTION
PC.A.3.2.2 (f) (i)
Performance Chart at Generating Unit stator terminals
PC.A.3.2.2 (b)
Output Usable (on a monthly basis)
PC.A.5.3.2 (d)
Option 1 (iii)
GOVERNOR AND ASSOCIATED PRIME MOVER
PARAMETERS
UNITS
DATA
CATEGORY
SPD
MW
SPD
Boiler time constant (Stored Active Energy)
S
DPD II
HP turbine response ratio: (Proportion of Primary
Response arising from HP turbine)
%
DPD II
HP turbine response ratio: (Proportion of High Frequency
Response arising from HP turbine)
%
DPD II
- Maximum Setting
Hz
DPD II
- Normal Setting
Hz
DPD II
- Minimum Setting
Hz
DPD II
Reheater Time Constant
sec
DPD II
Boiler Time Constant
sec
DPD II
HP Power Fraction
%
DPD II
IP Power Fraction
%
DPD II
Maximum droop
%
DPD II
Minimum droop
%
DPD II
±Hz
DPD II
Option 1
BOILER & STEAM TURBINE DATA
Part of
PC.A.5.3.2 (d)
Option 2 (i)
Option 2
All Generating Units
Governor Deadband
Part of
PC.A.5.3.2 (d)
Option 2 (ii)
Steam Units
Part of
PC.A.5.3.2 (d)
Option 2 (iii)
Gas Turbine Units
Part of
PC.A.5.3.2 (e)
UNIT CONTROL OPTIONS
Waste Heat Recovery Boiler Time Constant
Maximum frequency deadband
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PC
REFERENCE
UNITS
DATA
CATEGORY
Normal frequency deadband
±Hz
DPD II
Minimum frequency deadband
±Hz
DPD II
Maximum Output deadband
±MW
DPD II
Normal Output deadband
±MW
DPD II
Minimum Output deadband
±MW
DPD II
Maximum
Hz
DPD II
Normal
Hz
DPD II
Minimum
Hz
DPD II
Yes/No
DPD II
DATA DESCRIPTION
Frequency settings between which Unit Load Controller
droop applies:
Sustained response normally selected
PC.A.3.2.2 (f) (ii) Performance Chart of a Power Park Modules at the
connection point
PC.A.3.2.2 (b)
Output Usable (on a monthly basis)
PC.A.3.2.2 (e)
and (j)
DC CONVERTER STATION DATA
SPD
MW
SPD
Import MW available in excess of Registered Import
Capacity.
MW
SPD
Time duration for which MW in excess of Registered
Import Capacity is available
Min
SPD
Export MW available in excess of Registered Capacity.
MW
SPD
Time duration for which MW in excess of Registered
Capacity is available
Min
SPD
Nominal loading rate
MW/s
DPD I
Maximum (emergency) loading rate
MW/s
DPD I
Nominal loading rate
MW/s
DPD I
Maximum (emergency) loading rate
MW/s
DPD I
ACTIVE POWER TRANSFER CAPABILITY (PC.A.3.2.2)
Part of
PC.A.5.4.3.3
LOADING PARAMETERS
MW Export
MW Import
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APPENDIX E - OFFSHORE TRANSMISSION SYSTEM AND OTSDUW
PLANT AND APPARATUS TECHNICAL AND DESIGN CRITERIA
PC.E.1
In the absence of any relevant Electrical Standards, Offshore Transmission Licensees and
Generators undertaking OTSDUW are required to ensure that all equipment used in the
construction of their network is:
(i)
Fully compliant and suitably designed to any relevant Technical Specification;
(ii)
Suitable for use and operation in an Offshore environment, where such parts of the
Offshore Transmission System and OTSDUW Plant and Apparatus are located in
Offshore Waters and are not installed in an area that is protected from that Offshore
environment, and
(iii) Compatible with any relevant Electrical Standards or Technical Specifications at the
Offshore Grid Entry Point and Interface Point.
PC.E.2
ITEM No.
1
2*
3*
4*
The table below identifies the technical and design criteria that will be used in the design and
development of an Offshore Transmission System and OTSDUW Plant and Apparatus.
DOCUMENT
National Electricity Transmission System Security and Quality of
Supply Standard
Planning Limits for Voltage Fluctuations Caused by Industrial,
Commercial and Domestic Equipment in the United Kingdom
Planning Levels for Harmonic Voltage Distortion and the Connection
of Non-Linear Loads to Transmission Systems and Public Electricity
Supply Systems in the United Kingdom
Planning Limits for Voltage Unbalance in the United Kingdom
REFERENCE No.
Version [ ]
ER P28
ER G5/4
ER P29
* Note:- Items 2, 3 and 4 above shall only apply at the Interface Point.
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CONNECTION CONDITIONS
(CC)
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
CC.1 INTRODUCTION .......................................................................................................................................2
CC.2 OBJECTIVE ..............................................................................................................................................2
CC.3 SCOPE ......................................................................................................................................................2
CC.4 PROCEDURE ...........................................................................................................................................4
CC.5 CONNECTION ..........................................................................................................................................4
CC.6 TECHNICAL, DESIGN AND OPERATIONAL CRITERIA .........................................................................6
CC.7 SITE RELATED CONDITIONS ...............................................................................................................44
CC.8 ANCILLARY SERVICES .........................................................................................................................51
APPENDIX 1 - SITE RESPONSIBILITY SCHEDULES .....................................................................................53
PROFORMA FOR SITE RESPONSIBILITY SCHEDULE ..........................................................................56
APPENDIX 2 - OPERATION DIAGRAMS..........................................................................................................60
PART 1A - PROCEDURES RELATING TO OPERATION DIAGRAMS ....................................................60
PART 1B - PROCEDURES RELATING TO GAS ZONE DIAGRAMS .......................................................63
PART 2 - NON-EXHAUSTIVE LIST OF APPARATUS TO BE INCLUDED ON OPERATION
DIAGRAMS .................................................................................................................................................64
APPENDIX 3 - MINIMUM FREQUENCY RESPONSE REQUIREMENT PROFILE AND OPERATING
RANGE FOR NEW POWER STATIONS AND DC CONVERTER STATIONS .................................................66
APPENDIX 4 - FAULT RIDE THROUGH REQUIREMENTS .............................................................................71
APPENDIX 4A ............................................................................................................................................71
APPENDIX 4B ............................................................................................................................................77
APPENDIX 5 - TECHNICAL REQUIREMENTS LOW FREQUENCY RELAYS FOR THE AUTOMATIC
DISCONNECTION OF SUPPLIES AT LOW FREQUENCY ..............................................................................83
APPENDIX 6 - PERFORMANCE REQUIREMENTS FOR CONTINUOUSLY ACTING AUTOMATIC
EXCITATION CONTROL SYSTEMS FOR ONSHORE SYNCHRONOUS GENERATING UNITS ...................85
APPENDIX 7 - PERFORMANCE REQUIREMENTS FOR CONTINUOUSLY ACTING AUTOMATIC
VOLTAGE CONTROL SYSTEMS FOR ONSHORE NON-SYNCHRONOUS GENERATING UNITS,
ONSHORE DC CONVERTERS, ONSHORE POWER PARK MODULES AND OTSDUW PLANT AND
APPARATUS AT THE INTERFACE POINT ......................................................................................................89
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CC.1
INTRODUCTION
CC.1.1
The Connection Conditions ("CC") specify both:
(a) the minimum technical, design and operational criteria which must be complied with by:
(i)
any User connected to or seeking connection with the National Electricity
Transmission System, or
(ii)
Generators (other than in respect of Small Power Stations) or DC Converter
Station owners connected to or seeking connection to a User's System which is
located in Great Britain or Offshore, and
(b) the minimum technical, design and operational criteria with which NGET will comply in
relation to the part of the National Electricity Transmission System at the
Connection Site with Users. In the case of any OTSDUW Plant and Apparatus, the
CC also specify the minimum technical, design and operational criteria which must be
complied with by the User when undertaking OTSDUW.
CC.2
OBJECTIVE
CC.2.1
The objective of the CC is to ensure that by specifying minimum technical, design and
operational criteria the basic rules for connection to the National Electricity Transmission
System and (for certain Users) to a User's System are similar for all Users of an equivalent
category and will enable NGET to comply with its statutory and Transmission Licence
obligations.
CC.2.2
In the case of any OTSDUW the objective of the CC is to ensure that by specifying the
minimum technical, design and operational criteria the basic rules relating to an Offshore
Transmission System designed and constructed by an Offshore Transmission Licensee
and designed and/or constructed by a User under the OTSDUW Arrangements are
equivalent.
CC.2.3
Provisions of the CC which apply in relation to OTSDUW and OTSUA, and/or a
Transmission Interface Site, shall (in any particular case) apply up to the OTSUA Transfer
Time, whereupon such provisions shall (without prejudice to any prior non-compliance)
cease to apply, without prejudice to the continuing application of provisions of the CC
applying in relation to the relevant Offshore Transmission System and/or Connection
Site. It is the case therefore that in cases where the OTSUA become operational prior to the
OTSUA Transfer Time that a Generator is required to comply with this CC both as it
applies to its Plant and Apparatus at a Connection Site\Connection Point and the
OTSUA at the Transmission Interface Site/Transmission Interface Point until the
OTSUA Transfer Time and this CC shall be construed accordingly.
CC.2.4
In relation to OTSDUW, provisions otherwise to be contained in a Bilateral Agreement may
be contained in the Construction Agreement, and accordingly a reference in the CC to a
relevant Bilateral Agreement includes the relevant Construction Agreement.
CC.3
SCOPE
CC.3.1
The CC applies to NGET and to Users, which in the CC means:
(a) Generators (other than those which only have Embedded Small Power Stations),
including those undertaking OTSDUW;
(b) Network Operators;
(c) Non-Embedded Customers;
(d) DC Converter Station owners; and
(e) BM Participants and Externally Interconnected System Operators in respect of
CC.6.5 only.
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CC.3.2
The above categories of User will become bound by the CC prior to them generating,
distributing, supplying or consuming, as the case may be, and references to the various
categories should, therefore, be taken as referring to them in that prospective role as well as
to Users actually connected.
CC.3.3
Embedded Medium Power Stations not subject to a Bilateral Agreement and Embedded
DC Converter Stations not subject to a Bilateral Agreement Provisions.
The following provisions apply in respect of Embedded Medium Power Stations not
subject to a Bilateral Agreement and Embedded DC Converter Stations not subject to a
Bilateral Agreement.
CC.3.3.1
The obligations within the CC that are expressed to be applicable to Generators in respect
of Embedded Medium Power Stations not subject to a Bilateral Agreement and DC
Converter Station Owners in respect of Embedded DC Converter Stations not subject to
a Bilateral Agreement (where the obligations are in each case listed in CC.3.3.2) shall be
read and construed as obligations that the Network Operator within whose System any
such Medium Power Station or DC Converter Station is Embedded must ensure are
performed and discharged by the Generator or the DC Converter Station owner.
Embedded Medium Power Stations not subject to a Bilateral Agreement and Embedded
DC Converter Stations not subject to a Bilateral Agreement which are located Offshore
and which are connected to an Onshore User System will be required to meet the
applicable requirements of the Grid Code as though they are an Onshore Generator or
Onshore DC Converter Station Owner connected to an Onshore User System Entry
Point.
CC.3.3.2
The Network Operator within whose System a Medium Power Station not subject to a
Bilateral Agreement is Embedded or a DC Converter Station not subject to a Bilateral
Agreement is Embedded must ensure that the following obligations in the CC are
performed and discharged by the Generator in respect of each such Embedded Medium
Power Station or the DC Converter Station owner in the case of an Embedded DC
Converter Station:
CC.5.1
CC.5.2.2
CC.5.3
CC.6.1.3
CC.6.1.5 (b)
CC.6.3.2, CC.6.3.3, CC.6.3.4, CC.6.3.6, CC.6.3.7, CC.6.3.8, CC.6.3.9, CC.6.3.10,
CC.6.3.12, CC.6.3.13, CC.6.3.15, CC.6.3.16
CC.6.4.4
CC.6.5.6 (where required by CC.6.4.4)
In respect of CC.6.2.2.2, CC.6.2.2.3, CC.6.2.2.5, CC.6.1.5(a), CC.6.1.5(b) and
CC.6.3.11 equivalent provisions as co-ordinated and agreed with the Network
Operator and Generator or DC Converter Station owner may be required. Details of
any such requirements will be notified to the Network Operator in accordance with
CC.3.5.
CC.3.3.3
In the case of Embedded Medium Power Stations not subject to a Bilateral Agreement
and Embedded DC Converter Stations not subject to a Bilateral Agreement the
requirements in:
CC.6.1.6
CC.6.3.8
CC.6.3.12
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CC.6.3.15
CC.6.3.16
that would otherwise have been specified in a Bilateral Agreement will be notified to the
relevant Network Operator in writing in accordance with the provisions of the CUSC and the
Network Operator must ensure such requirements are performed and discharged by the
Generator or the DC Converter Station owner.
CC.3.4
In the case of Offshore Embedded Power Stations connected to an Offshore User’s
System which directly connects to an Offshore Transmission System, any additional
requirements in respect of such Offshore Embedded Power Stations may be specified in
the relevant Bilateral Agreement with the Network Operator or in any Bilateral
Agreement between NGET and such Offshore Embedded Power Station.
CC.3.5
In the case of a Generator undertaking OTSDUW connecting to an Onshore Network
Operator’s System, any additional requirements in respect of such OTSDUW Plant and
Apparatus will be specified in the relevant Bilateral Agreement with the Generator. For the
avoidance of doubt, requirements applicable to Generators undertaking OTSDUW and
connecting to a Network Operator’s User System, shall be consistent with those applicable
requirements of Generators undertaking OTSDUW and connecting to a Transmission
Interface Point.
CC.4
PROCEDURE
CC.4.1
The CUSC contains certain provisions relating to the procedure for connection to the
National Electricity Transmission System or, in the case of Embedded Power Stations
or Embedded DC Converter Stations, becoming operational and includes provisions
relating to certain conditions to be complied with by Users prior to and during the course of
NGET notifying the User that it has the right to become operational. The procedure for a
User to become connected is set out in the Compliance Processes.
CC.5
CONNECTION
CC.5.1
The provisions relating to connecting to the National Electricity Transmission System (or
to a User's System in the case of a connection of an Embedded Large Power Station or
Embedded Medium Power Station or Embedded DC Converter Station) are contained in:
(a) the CUSC and/or CUSC Contract (or in the relevant application form or offer for a
CUSC Contract);
(b) or, in the case of an Embedded Development, the relevant Distribution Code and/or
the Embedded Development Agreement for the connection (or in the relevant
application form or offer for an Embedded Development Agreement),
and include provisions relating to both the submission of information and reports relating to
compliance with the relevant Connection Conditions for that User, Safety Rules,
commissioning programmes, Operation Diagrams and approval to connect (and their
equivalents in the case of Embedded Medium Power Stations not subject to a Bilateral
Agreement or Embedded DC Converter Stations not subject to a Bilateral Agreement).
References in the CC to the "Bilateral Agreement” and/or “Construction Agreement"
and/or “Embedded Development Agreement” shall be deemed to include references to the
application form or offer therefor.
CC.5.2
Items For Submission
CC.5.2.1
Prior to the Completion Date (or, where the Generator is undertaking OTSDUW, any later
date specified) under the Bilateral Agreement and/or Construction Agreement, the
following is submitted pursuant to the terms of the Bilateral Agreement and/or
Construction Agreement:
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(a) updated Planning Code data (both Standard Planning Data and Detailed Planning
Data), with any estimated values assumed for planning purposes confirmed or, where
practical, replaced by validated actual values and by updated estimates for the future
and by updated forecasts for Forecast Data items such as Demand, pursuant to the
requirements of the Planning Code;
(b) details of the Protection arrangements and settings referred to in CC.6;
(c) copies of all Safety Rules and Local Safety Instructions applicable at Users' Sites
which will be used at the NGET/User interface (which, for the purpose of OC8, must be
to NGET’s satisfaction regarding the procedures for Isolation and Earthing. For User
Sites in Scotland and Offshore NGET will consult the Relevant Transmission
Licensee when determining whether the procedures for Isolation and Earthing are
satisfactory);
(d) information to enable NGET to prepare Site Responsibility Schedules on the basis of
the provisions set out in Appendix 1;
(e) an Operation Diagram for all HV Apparatus on the User side of the Connection
Point as described in CC.7;
(f)
the proposed name of the User Site (which shall not be the same as, or confusingly
similar to, the name of any Transmission Site or of any other User Site);
(g) written confirmation that Safety Co-ordinators acting on behalf of the User are
authorised and competent pursuant to the requirements of OC8;
(h) RISSP prefixes pursuant to the requirements of OC8. NGET is required to circulate
prefixes utilising a proforma in accordance with OC8;
(i)
a list of the telephone numbers for Joint System Incidents at which senior
management representatives nominated for the purpose can be contacted and
confirmation that they are fully authorised to make binding decisions on behalf of the
User, pursuant to OC9;
(j)
a list of managers who have been duly authorised to sign Site Responsibility
Schedules on behalf of the User;
(k) information to enable NGET to prepare Site Common Drawings as described in CC.7;
(l)
a list of the telephone numbers for the Users facsimile machines referred to in
CC.6.5.9; and
(m) for Sites in Scotland and Offshore a list of persons appointed by the User to undertake
operational duties on the User’s System (including any OTSDUW prior to the OTSUA
Transfer Time) and to issue and receive operational messages and instructions in
relation to the User’s System (including any OTSDUW prior to the OTSUA Transfer
Time); and an appointed person or persons responsible for the maintenance and testing
of User’s Plant and Apparatus.
CC.5.2.2
Prior to the Completion Date the following must be submitted to NGET by the Network
Operator in respect of an Embedded Development:
(a) updated Planning Code data (both Standard Planning Data and Detailed Planning
Data), with any estimated values assumed for planning purposes confirmed or, where
practical, replaced by validated actual values and by updated estimates for the future
and by updated forecasts for Forecast Data items such as Demand, pursuant to the
requirements of the Planning Code;
(b) details of the Protection arrangements and settings referred to in CC.6;
(c) the proposed name of the Embedded Medium Power Station or Embedded DC
Converter Station Site (which shall be agreed with NGET unless it is the same as, or
confusingly similar to, the name of other Transmission Site or User Site);
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CC.5.2.3
Prior to the Completion Date contained within an Offshore Transmission Distribution
Connection Agreement the following must be submitted to NGET by the Network
Operator in respect of a proposed new Interface Point within its User System:
(a) updated Planning Code data (both Standard Planning Data and Detailed Planning
Data), with any estimated values assumed for planning purposes confirmed or, where
practical, replaced by validated actual values and by updated estimates for the future
and by updated forecasts for Forecast Data items such as Demand, pursuant to the
requirements of the Planning Code;
(b) details of the Protection arrangements and settings referred to in CC.6;
(c) the proposed name of the Interface Point (which shall not be the same as, or
confusingly similar to, the name of any Transmission Site or of any other User Site);
CC.5.2.4
In the case of OTSDUW Plant and Apparatus (in addition to items under CC.5.2.1 in
respect of the Connection Site), prior to the Completion Date (or any later date specified)
under the Construction Agreement the following must be submitted to NGET by the User
in respect of the proposed new Connection Point and Interface Point:
(a) updated Planning Code data (Standard Planning Data, Detailed Planning Data and
OTSDUW Data and Information), with any estimated values assumed for planning
purposes confirmed or, where practical, replaced by validated actual values and by
updated estimates for the future and by updated forecasts for Forecast Data items
such as Demand, pursuant to the requirements of the Planning Code;
(b) details of the Protection arrangements and settings referred to in CC.6;
(c) information to enable preparation of the Site Responsibility Schedules at the
Transmission Interface Site on the basis of the provisions set out in Appendix 1.
(d) the proposed name of the Interface Point (which shall not be the same as, or
confusingly similar to, the name of any Transmission Site or of any other User Site);
CC.5.3
(a) Of the items CC.5.2.1 (c), (e), (g), (h), (k) and (m) need not be supplied in respect of
Embedded Power Stations or Embedded DC Converter Stations,
(b) item CC.5.2.1(i) need not be supplied in respect of Embedded Small Power Stations
and Embedded Medium Power Stations or Embedded DC Converter Stations with
a Registered Capacity of less than 100MW, and
(c) items CC.5.2.1(d) and (j) are only needed in the case where the Embedded Power
Station or the Embedded DC Converter Station is within a Connection Site with
another User.
CC.5.4
In addition, at the time the information is given under CC.5.2(g), NGET will provide written
confirmation to the User that the Safety Co-ordinators acting on behalf of NGET are
authorised and competent pursuant to the requirements of OC8.
CC.6
TECHNICAL, DESIGN AND OPERATIONAL CRITERIA
CC.6.1
National Electricity Transmission System Performance Characteristics
CC.6.1.1
NGET shall ensure that, subject as provided in the Grid Code, the National Electricity
Transmission System complies with the following technical, design and operational criteria
in relation to the part of the National Electricity Transmission System at the Connection
Site with a User and in the case of OTSDUW Plant and Apparatus, a Transmission
Interface Point (unless otherwise specified in CC.6) although in relation to operational
criteria NGET may be unable (and will not be required) to comply with this obligation to the
extent that there are insufficient Power Stations or User Systems are not available or
Users do not comply with NGET's instructions or otherwise do not comply with the Grid
Code and each User shall ensure that its Plant and Apparatus complies with the criteria set
out in CC.6.1.5.
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Grid Frequency Variations
CC.6.1.2
The Frequency of the National Electricity Transmission System shall be nominally 50Hz
and shall be controlled within the limits of 49.5 - 50.5Hz unless exceptional circumstances
prevail.
CC.6.1.3
The System Frequency could rise to 52Hz or fall to 47Hz in exceptional circumstances.
Design of User's Plant and Apparatus and OTSDUW Plant and Apparatus must enable
operation of that Plant and Apparatus within that range in accordance with the following:
Frequency Range
51.5Hz - 52Hz
51Hz - 51.5Hz
49.0Hz - 51Hz
47.5Hz - 49.0Hz
47Hz - 47.5Hz
Requirement
Operation for a period of at least 15 minutes
each time the Frequency is above 51.5Hz.
Operation for a period of at least 90 minutes
each time the Frequency is above 51Hz.
Continuous operation is required
Operation for a period of at least 90 minutes
each time the Frequency is below 49.0Hz.
Operation for a period of at least 20 seconds
each time the Frequency is below 47.5Hz.
is required
is required
is required
is required
For the avoidance of doubt, disconnection, by frequency or speed based relays is not
permitted within the frequency range 47.5Hz to 51.5Hz, unless agreed with NGET in
accordance with CC.6.3.12.
Grid Voltage Variations
CC.6.1.4
Subject as provided below, the voltage on the 400kV part of the National Electricity
Transmission System at each Connection Site with a User (and in the case of OTSDUW
Plant and Apparatus, a Transmission Interface Point) will normally remain within 5% of
the nominal value unless abnormal conditions prevail. The minimum voltage is -10% and the
maximum voltage is +10% unless abnormal conditions prevail, but voltages between +5%
and +10% will not last longer than 15 minutes unless abnormal conditions prevail. Voltages
on the 275kV and 132kV parts of the National Electricity Transmission System at each
Connection Site with a User (and in the case of OTSDUW Plant and Apparatus, a
Transmission Interface Point) will normally remain within the limits 10% of the nominal
value unless abnormal conditions prevail. At nominal System voltages below 132kV the
voltage of the National Electricity Transmission System at each Connection Site with a
User (and in the case of OTSDUW Plant and Apparatus, a Transmission Interface Point)
will normally remain within the limits 6% of the nominal value unless abnormal conditions
prevail. Under fault conditions, voltage may collapse transiently to zero at the point of fault
until the fault is cleared. The normal operating ranges of the National Electricity
Transmission System are summarised below:
National Electricity Transmission System
Nominal Voltage
400kV
275kV
132kV
Normal Operating Range
400kV 5%
275kV 10%
132kV 10%
NGET and a User may agree greater or lesser variations in voltage to those set out above in
relation to a particular Connection Site, and insofar as a greater or lesser variation is
agreed, the relevant figure set out above shall, in relation to that User at the particular
Connection Site, be replaced by the figure agreed.
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Voltage Waveform Quality
CC.6.1.5
All Plant and Apparatus connected to the National Electricity Transmission System, and
that part of the National Electricity Transmission System at each Connection Site or, in
the case of OTSDUW Plant and Apparatus, at each Interface Point, should be capable of
withstanding the following distortions of the voltage waveform in respect of harmonic content
and phase unbalance:
(a) Harmonic Content
The Electromagnetic Compatibility Levels for harmonic distortion on the Onshore
Transmission System from all sources under both Planned Outage and fault outage
conditions, (unless abnormal conditions prevail) shall comply with the levels shown in
the tables of Appendix A of Engineering Recommendation G5/4.
The
Electromagnetic Compatibility Levels for harmonic distortion on an Offshore
Transmission System will be defined in relevant Bilateral Agreements.
Engineering Recommendation G5/4 contains planning criteria which NGET will apply
to the connection of non-linear Load to the National Electricity Transmission
System, which may result in harmonic emission limits being specified for these Loads
in the relevant Bilateral Agreement. The application of the planning criteria will take
into account the position of existing and prospective Users’ Plant and Apparatus (and
OTSDUW Plant and Apparatus) in relation to harmonic emissions. Users must
ensure that connection of distorting loads to their User Systems do not cause any
harmonic emission limits specified in the Bilateral Agreement, or where no such limits
are specified, the relevant planning levels specified in Engineering Recommendation
G5/4 to be exceeded.
(b) Phase Unbalance
Under Planned Outage conditions, the weekly 95 percentile of Phase (Voltage)
Unbalance, calculated in accordance with IEC 61000-4-30 and IEC 61000-3-13, on the
National Electricity Transmission System for voltages above 150kV should remain,
in England and Wales, below 1.5%, and in Scotland, below 2%, and for voltages of
150kV and below, across GB below 2%, unless abnormal conditions prevail and
Offshore (or in the case of OTSDUW, OTSDUW Plant and Apparatus) will be defined
in relevant Bilateral Agreements.
The Phase Unbalance is calculated from the ratio of root mean square (rms) of negative
phase sequence voltage to rms of positive phase sequence voltage, based on 10minute average values, in accordance with IEC 61000-4-30.
CC.6.1.6
Across GB, under the Planned Outage conditions stated in CC.6.1.5(b) infrequent short
duration peaks with a maximum value of 2% are permitted for Phase (Voltage) Unbalance,
for voltages above 150kV, subject to the prior agreement of NGET under the Bilateral
Agreement and in relation to OTSDUW, the Construction Agreement. NGET will only
agree following a specific assessment of the impact of these levels on Transmission
Apparatus and other Users Apparatus with which it is satisfied.
Voltage Fluctuations
CC.6.1.7
Voltage changes at a Point of Common Coupling on the Onshore Transmission System
shall not exceed:
(a) The limits specified in Table CC.6.1.7 with the stated frequency of occurrence, where:
(i)
%Vsteadystate = │100 x
Vsteadystate
V0
│
and
%Vmax =100 x
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(ii)
V0 is the initial steady state system voltage;
(iii)
Vsteadystate is the system voltage reached when the rate of change of system
voltage over time is less than or equal to 0.5% over 1 second and Vsteadystate is
the absolute value of the difference between Vsteadystate and V0;
(iv)
Vmax is the absolute value of the maximum change in the system voltage relative
to the initial steady state system voltage of V0;
(v)
All voltages are the root mean square of the voltage measured over one cycle
refreshed every half a cycle as per IEC 61000-4-30;
(vi)
The voltage changes specified are the absolute maximum allowed, applied to
phase to ground or phase to phase voltages whichever is the highest change;
(vii)
Voltage changes in category 3 do not exceed the limits depicted in the time
dependant characteristic shown in Figure CC.6.1.7;
(viii)
Voltage changes in category 3 only occur infrequently, typically not planned more
than once per year on average over the lifetime of a connection, and in
circumstances notified to NGET, such as for example commissioning in
accordance with a commissioning programme, implementation of a planned
outage notified in accordance with OC2 or an Operation or Event notified in
accordance with OC7; and
(ix)
For connections with a Completion Date after 1 September 2015 and where
voltage changes would constitute a risk to the National Electricity
Transmission System or, in NGET’s view, the System of any User, Bilateral
Agreements may include provision for NGET to reasonably limit the number of
voltage changes in category 2 or 3 to a lower number than specified in Table
CC.6.1.7 to ensure that the total number of voltage changes at the Point of
Common Coupling across multiple Users remains within the limits of Table
CC.6.1.7.
st
Category
Maximum number of
Occurrences
%Vmax & %Vsteadystate
1
No Limit
│%Vmax │≤ 1% &
│%Vsteadystate│ ≤ 1%
3600
0.304
2
√2.5 ×%∆Vmax
1% < │%Vmax│ ≤ 3% &
│%Vsteadystate │≤ 3%
occurrences per hour with
events evenly distributed
For decreases in voltage:
1
%Vmax ≤ 12% &
%Vsteadystate ≤ 3%
3
No more than 4 per day for
Commissioning, Maintenance
and Fault Restoration
For increases in voltage:
2
%Vmax ≤ 5% &
%Vsteadystate ≤ 3%
(see Figure CC6.1.7)
Table CC.6.1.7 - Limits for Rapid Voltage Changes
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1
2
A decrease in voltage of up to 12% is permissible for up to 80ms, as highlighted in the
shaded area in Figure CC.6.1.7, reducing to up to 10% after 80ms and to up to 3% after 2
seconds.
An increase in voltage of up to 5% is permissible if it is reduced to up to 3% after 0.5
seconds.
Voltage
Non-compliant zone
V0+5%
V0+3%
V0
V03%
Compliant zone
Vsteadystate is reached when
dv/dt  0.5% over 1s
V010%
V012%
Non-compliant zone
80ms 0.5 s
2s
Time
Figure CC.6.1.7 Time and magnitude limits for a category 3 Rapid Voltage Change
(b) For voltages above 132kV, Flicker Severity (Short Term) of 0.8 Unit and a Flicker
Severity (Long Term) of 0.6 Unit, for voltages 132kV and below, Flicker Severity
(Short Term) of 1.0 Unit and a Flicker Severity (Long Term) of 0.8 Unit, as set out in
Engineering Recommendation P28 as current at the Transfer Date.
CC.6.1.8
Voltage fluctuations at a Point of Common Coupling with a fluctuating Load directly
connected to an Offshore Transmission System (or in the case of OTSDUW, OTSDUW
Plant and Apparatus) shall not exceed the limits set out in the Bilateral Agreement.
Sub-Synchronous Resonance and Sub-Synchronous Torsional Interaction
CC.6.1.9
NGET shall ensure that Users' Plant and Apparatus will not be subject to unacceptable
Sub-Synchronous Oscillation conditions as specified in the relevant Licence Standards.
CC.6.1.10
NGET shall ensure where necessary, and in consultation with Transmission Licensees
where required, that any relevant site specific conditions applicable at a User's Connection
Site, including a description of the Sub-Synchronous Oscillation conditions considered in the
application of the relevant License Standards, are set out in the User's Bilateral
Agreement.
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CC.6.2
Plant and Apparatus relating to Connection Site and Interface Point
The following requirements apply to Plant and Apparatus relating to the Connection Point,
and OTSDUW Plant and Apparatus relating to the Interface Point (until the OTSUA
Transfer Time) and Connection Point which (except as otherwise provided in the relevant
paragraph) each User must ensure are complied with in relation to its Plant and Apparatus
and which in the case of CC.6.2.2.2.2, CC.6.2.3.1.1 and CC.6.2.1.1(b) only, NGET must
ensure are complied with in relation to Transmission Plant and Apparatus, as provided in
those paragraphs.
CC.6.2.1
General Requirements
CC.6.2.1.1
(a) The design of connections between the National Electricity Transmission System
and:
(i)
any Generating Unit (other than a CCGT Unit or Power Park Unit) DC
Converter, Power Park Module or CCGT Module, or
(ii)
any Network Operator’s User System, or
(iii) Non-Embedded Customers equipment;
will be consistent with the Licence Standards.
In the case of OTSDUW, the design of the OTSUA’s connections at the Interface Point
and Connection Point will be consistent with Licence Standards.
(b) The National Electricity Transmission System (and any OTSDUW Plant and
Apparatus) at nominal System voltages of 132kV and above is/shall be designed to be
earthed with an Earth Fault Factor of, in England and Wales or Offshore, below 1.4
and in Scotland, below 1.5. Under fault conditions the rated Frequency component of
voltage could fall transiently to zero on one or more phases or, in England and Wales,
rise to 140% phase-to-earth voltage, or in Scotland, rise to 150% phase-to-earth
voltage. The voltage rise would last only for the time that the fault conditions exist. The
fault conditions referred to here are those existing when the type of fault is single or two
phase-to-earth.
(c) For connections to the National Electricity Transmission System at nominal System
voltages of below 132kV the earthing requirements and voltage rise conditions will be
advised by NGET as soon as practicable prior to connection and in the case of
OTSDUW Plant and Apparatus shall be advised to NGET by the User.
CC.6.2.1.2
Substation Plant and Apparatus
(a) The following provisions shall apply to all Plant and Apparatus which is connected at
the voltage of the Connection Point (and OTSDUW Plant and Apparatus at the
Interface Point) and which is contained in equipment bays that are within the
Transmission busbar Protection zone at the Connection Point. This includes circuit
breakers, switch disconnectors, disconnectors, Earthing Devices, power transformers,
voltage transformers, reactors, current transformers, surge arresters, bushings, neutral
equipment, capacitors, line traps, coupling devices, external insulation and insulation
co-ordination devices. Where necessary, this is as more precisely defined in the
Bilateral Agreement.
(i)
Plant and/or Apparatus prior to 1st January 1999
Each item of such Plant and/or Apparatus which at 1st January 1999 is either :
installed; or
owned (but is either in storage, maintenance or awaiting installation); or
ordered;
and is the subject of a Bilateral Agreement with regard to the purpose for which it
is in use or intended to be in use, shall comply with the relevant
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standards/specifications applicable at the time that the Plant and/or Apparatus
was designed (rather than commissioned) and any further requirements as
specified in the Bilateral Agreement.
(ii)
Plant and/or Apparatus post 1st January 1999 for a new Connection Point
(including OTSDUW Plant and Apparatus at the Interface Point)
Each item of such Plant and/or Apparatus installed in relation to a new
Connection Point (or OTSDUW Plant and Apparatus at the Interface Point)
after 1st January 1999 shall comply with the relevant Technical Specifications
and any further requirements identified by NGET, acting reasonably, to reflect the
options to be followed within the Technical Specifications and/or to complement
if necessary the Technical Specifications so as to enable NGET to comply with
its obligations in relation to the National Electricity Transmission System or, in
Scotland or Offshore, the Relevant Transmission Licensee to comply with its
obligations in relation to its Transmission System. This information, including the
application dates of the relevant Technical Specifications, will be as specified in
the Bilateral Agreement.
(iii) New Plant and/or Apparatus post 1st January 1999 for an existing Connection
Point (including OTSDUW Plant and Apparatus at the Interface Point)
Each new additional and/or replacement item of such Plant and/or Apparatus
installed in relation to a change to an existing Connection Point (or OTSDUW
Plant and Apparatus at the Interface Point and Connection Point) after 1st
January 1999 shall comply with the standards/specifications applicable when the
change was designed, or such other standards/specifications as necessary to
ensure that the item of Plant and/or Apparatus is reasonably fit for its intended
purpose having due regard to the obligations of NGET, the relevant User and, in
Scotland, or Offshore, also the Relevant Transmission Licensee under their
respective Licences. Where appropriate this information, including the application
dates of the relevant standards/specifications, will be as specified in the varied
Bilateral Agreement.
(iv) Used Plant and/or Apparatus being moved, re-used or modified
If, after its installation, any such item of Plant and/or Apparatus is subsequently:
moved to a new location; or
used for a different purpose; or
otherwise modified;
then the standards/specifications as described in (i), (ii), or (iii) above as applicable
will apply as appropriate to such Plant and/or Apparatus, which must be
reasonably fit for its intended purpose having due regard to the obligations of
NGET, the relevant User and, in Scotland or Offshore, also the Relevant
Transmission Licensee under their respective Licences.
(b) NGET shall at all times maintain a list of those Technical Specifications and additional
requirements which might be applicable under this CC.6.2.1.2 and which may be
referenced by NGET in the Bilateral Agreement. NGET shall provide a copy of the list
upon request to any User. NGET shall also provide a copy of the list to any new User
upon receipt of an application form for a Bilateral Agreement for a new Connection
Point.
(c) Where the User provides NGET with information and/or test reports in respect of Plant
and/or Apparatus which the User reasonably believes demonstrate the compliance of
such items with the provisions of a Technical Specification then NGET shall promptly
and without unreasonable delay give due and proper consideration to such information.
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(d) Plant and Apparatus shall be designed, manufactured and tested in premises with an
accredited certificate in accordance with the quality assurance requirements of the
relevant standard in the BS EN ISO 9000 series (or equivalent as reasonably approved
by NGET) or in respect of test premises which do not include a manufacturing facility
premises with an accredited certificate in accordance with BS EN 45001.
(e) Each connection between a User and the National Electricity Transmission System
must be controlled by a circuit-breaker (or circuit breakers) capable of interrupting the
maximum short circuit current at the point of connection. The Seven Year Statement
gives values of short circuit current and the rating of Transmission circuit breakers at
existing and committed Connection Points for future years.
(f)
Each connection between a Generator undertaking OTSDUW or an Onshore
Transmission Licensee, must be controlled by a circuit breaker (or circuit breakers)
capable of interrupting the maximum short circuit current at the Transmission Interface
Point. The Seven Year Statement gives values of short circuit current and the rating
of Transmission circuit breakers at existing and committed Transmission Interface
Points for future years.
CC.6.2.2
Requirements at Connection Points or, in the case of OTSDUW at Interface Points that
relate to Generators or OTSDUW Plant and Apparatus or DC Converter Station owners
CC.6.2.2.1
Not Used.
CC.6.2.2.2
Generating Unit,
Arrangements
CC.6.2.2.2.1
Minimum Requirements
OTSDUW
Plant
and
Apparatus
and
Power
Station
Protection
Protection of Generating Units (other than Power Park Units), DC Converters, OTSDUW
Plant and Apparatus or Power Park Modules and their connections to the National
Electricity Transmission System shall meet the requirements given below. These are
necessary to reduce the impact on the National Electricity Transmission System of faults
on OTSDUW Plant and Apparatus circuits or circuits owned by Generators or DC
Converter Station owners.
CC.6.2.2.2.2
Fault Clearance Times
(a) The required fault clearance time for faults on the Generator's or DC Converter Station
owner’s equipment directly connected to the National Electricity Transmission
System or OTSDUW Plant and Apparatus and for faults on the National Electricity
Transmission System directly connected to the Generator or DC Converter Station
owner's equipment or OTSDUW Plant and Apparatus, from fault inception to the circuit
breaker arc extinction, shall be set out in the Bilateral Agreement. The fault clearance
time specified in the Bilateral Agreement shall not be shorter than the durations
specified below:
(i)
80ms at 400kV
(ii)
100ms at 275kV
(iii) 120ms at 132kV and below
but this shall not prevent the User or NGET or the Generator (including in respect of
OTSDUW Plant and Apparatus) from selecting a shorter fault clearance time on their
own Plant and Apparatus provided Discrimination is achieved..
A longer fault clearance time may be specified in the Bilateral Agreement for faults on
the National Electricity Transmission System. A longer fault clearance time for faults
on the Generator or DC Converter Station owner's equipment or OTSDUW Plant and
Apparatus may be agreed with NGET in accordance with the terms of the Bilateral
Agreement but only if System requirements, in NGET's view, permit. The probability
that the fault clearance time stated in the Bilateral Agreement will be exceeded by any
given fault, must be less than 2%.
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(b) In the event that the required fault clearance time is not met as a result of failure to
operate on the Main Protection System(s) provided, the Generators or DC Converter
Station owners or Generators in the case of OTSDUW Plant and Apparatus shall,
except as specified below provide Independent Back-Up Protection. NGET will also
provide Back-Up Protection and NGET and the User’s Back-Up Protections will be
co-ordinated so as to provide Discrimination.
On a Generating Unit (other than a Power Park Unit), DC Converter or Power Park
Module or OTSDUW Plant and Apparatus in respect of which the Completion Date is
after 20 January 2016 and connected to the National Electricity Transmission
System at 400kV or 275kV and where two Independent Main Protections are
provided to clear faults on the HV Connections within the required fault clearance time,
the Back-Up Protection provided by the Generators (including in respect of OTSDUW
Plant and Apparatus) and DC Converter Station owner shall operate to give a fault
clearance time of no longer than 300ms at the minimum infeed for normal operation for
faults on the HV Connections. Where two Independent Main Protections are
installed the Back-Up Protection may be integrated into one (or both) of the
Independent Main Protection relays.
On a Generating Unit (other than a Power Park Unit), DC Converter or Power Park
Module or OTSDUW Plant and Apparatus in respect of which the Completion Date is
after 20 January 2016 and connected to the National Electricity Transmission
System at 132 kV and where only one Main Protection is provided to clear faults on
the HV Connections within the required fault clearance time, the Independent BackUp Protection provided by the Generator (including in respect of OTSDUW Plant and
Apparatus) and the DC Converter Station owner shall operate to give a fault
clearance time of no longer than 300ms at the minimum infeed for normal operation for
faults on the HV Connections.
On a Generating Unit (other than a Power Park Unit), DC Converter or Power Park
Module or OTSDUW Plant and Apparatus connected to the National Electricity
Transmission System and on Generating Units (other than a Power Park Unit), DC
Converters or Power Park Modules or OTSDUW Plant and Apparatus connected to
the National Electricity Transmission System at 400 kV or 275 kV or 132 kV, in
respect of which the Completion Date is before the 20 January 2016, the Back-Up
Protection or Independent Back-Up Protection shall operate to give a fault clearance
time of no longer than 800ms in England and Wales or 300ms in Scotland at the
minimum infeed for normal operation for faults on the HV Connections.
A Generating Unit (other than a Power Park Unit), DC Converter or Power Park
Module or OTSDUW Plant and Apparatus) with Back-Up Protection or Independent
Back-Up Protection will also be required to withstand, without tripping, the loading
incurred during the clearance of a fault on the National Electricity Transmission
System by breaker fail Protection at 400kV or 275kV or of a fault cleared by Back-Up
Protection where the Generator (including in the case of OTSDUW Plant and
Apparatus) or DC Converter is connected at 132kV and below. This will permit
Discrimination between Generator in respect of OTSDUW Plant and Apparatus or
DC Converter Station owners’ Back-Up Protection or Independent Back-Up
Protection and the Back-Up Protection provided on the National Electricity
Transmission System and other Users' Systems.
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(c) When the Generating Unit (other than Power Park Units), or the DC Converter or
Power Park Module or OTSDUW Plant and Apparatus is connected to the National
Electricity Transmission System at 400kV or 275kV, and in Scotland and Offshore
also at 132kV, and a circuit breaker is provided by the Generator (including in respect
of OTSDUW Plant and Apparatus) or the DC Converter Station owner, or NGET, as
the case may be, to interrupt fault current interchange with the National Electricity
Transmission System, or Generator's System, or DC Converter Station owner’s
System, as the case may be, circuit breaker fail Protection shall be provided by the
Generator (including in respect of OTSDUW Plant and Apparatus) or DC Converter
Station owner, or NGET, as the case may be, on this circuit breaker. In the event,
following operation of a Protection system, of a failure to interrupt fault current by these
circuit-breakers within the Fault Current Interruption Time, the circuit breaker fail
Protection is required to initiate tripping of all the necessary electrically adjacent circuitbreakers so as to interrupt the fault current within the next 200ms.
(d) The target performance for the System Fault Dependability Index shall be not less
than 99%. This is a measure of the ability of Protection to initiate successful tripping of
circuit breakers which are associated with the faulty item of Apparatus.
CC.6.2.2.3
Equipment to be provided
CC.6.2.2.3.1
Protection of Interconnecting Connections
The requirements for the provision of Protection equipment for interconnecting connections
will be specified in the Bilateral Agreement. In this CC the term "interconnecting
connections" means the primary conductors from the current transformer accommodation on
the circuit side of the circuit breaker to the Connection Point or the primary conductors from
the current transformer accommodation on the circuit side of the OTSDUW Plant and
Apparatus of the circuit breaker to the Transmission Interface Point.
CC.6.2.2.3.2
Circuit-breaker fail Protection
The Generator or DC Converter Station owner will install circuit breaker fail Protection
equipment in accordance with the requirements of the Bilateral Agreement. The
Generator or DC Converter Station owner will also provide a back-trip signal in the event of
loss of air from its pressurised head circuit breakers, during the Generating Unit (other than
a CCGT Unit or Power Park Unit) or CCGT Module or DC Converter or Power Park
Module run-up sequence, where these circuit breakers are installed.
CC.6.2.2.3.3
Loss of Excitation
The Generator must provide Protection to detect loss of excitation on a Generating Unit
and initiate a Generating Unit trip.
CC.6.2.2.3.4
Pole-Slipping Protection
Where, in NGET's reasonable opinion, System requirements dictate, NGET will specify in
the Bilateral Agreement a requirement for Generators to fit pole-slipping Protection on
their Generating Units.
CC.6.2.2.3.5
Signals for Tariff Metering
Generators and DC Converter Station owners will install current and voltage transformers
supplying all tariff meters at a voltage to be specified in, and in accordance with, the
Bilateral Agreement.
CC.6.2.2.4
Work on Protection Equipment
No busbar Protection, mesh corner Protection, circuit-breaker fail Protection relays, AC or
DC wiring (other than power supplies or DC tripping associated with the Generating Unit,
DC Converter or Power Park Module itself) may be worked upon or altered by the
Generator or DC Converter Station owner personnel in the absence of a representative of
NGET or in Scotland or Offshore, a representative of NGET, or written authority from NGET
to perform such work or alterations in the absence of a representative of NGET.
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CC.6.2.2.5
Relay Settings
Protection and relay settings will be co-ordinated (both on connection and subsequently)
across the Connection Point in accordance with the Bilateral Agreement and in relation to
OTSDUW Plant and Apparatus, across the Interface Point in accordance with the
Bilateral Agreement to ensure effective disconnection of faulty Apparatus.
CC.6.2.3
Requirements at Connection Points relating to Network Operators and Non-Embedded
Customers
CC.6.2.3.1
Protection Arrangements for Network Operators and Non-Embedded Customers
CC.6.2.3.1.1
Protection of Network Operator and Non-Embedded Customers User Systems directly
connected to the National Electricity Transmission System, shall meet the requirements
given below:
Fault Clearance Times
(a) The required fault clearance time for faults on Network Operator and Non-Embedded
Customer equipment directly connected to the National Electricity Transmission
System, and for faults on the National Electricity Transmission System directly
connected to the Network Operator’s or Non-Embedded Customer's equipment,
from fault inception to the circuit breaker arc extinction, shall be set out in each Bilateral
Agreement. The fault clearance time specified in the Bilateral Agreement shall not be
shorter than the durations specified below:
(i)
80ms at 400kV
(ii)
100ms at 275kV
(iii) 120ms at 132kV and below
but this shall not prevent the User or NGET from selecting a shorter fault clearance time
on its own Plant and Apparatus provided Discrimination is achieved.
For the purpose of establishing the Protection requirements in accordance with
CC.6.2.3.1.1 only, the point of connection of the Network Operator or NonEmbedded Customer equipment to the National Electricity Transmission System
shall be deemed to be the low voltage busbars at a Grid Supply Point, irrespective of
the ownership of the equipment at the Grid Supply Point.
A longer fault clearance time may be specified in the Bilateral Agreement for faults on
the National Electricity Transmission System. A longer fault clearance time for faults
on the Network Operator and Non-Embedded Customers equipment may be agreed
with NGET in accordance with the terms of the Bilateral Agreement but only if System
requirements in NGET's view permit. The probability that the fault clearance time stated
in the Bilateral Agreement will be exceeded by any given fault must be less than 2%.
(b) (i)
For the event of failure of the Protection systems provided to meet the above fault
clearance time requirements, Back-Up Protection shall be provided by the
Network Operator or Non-Embedded Customer as the case may be.
(ii)
NGET will also provide Back-Up Protection, which will result in a fault clearance
time longer than that specified for the Network Operator or Non-Embedded
Customer Back-Up Protection so as to provide Discrimination.
(iii) For connections with the National Electricity Transmission System at 132kV
and below, it is normally required that the Back-Up Protection on the National
Electricity Transmission System shall discriminate with the Network Operator
or Non-Embedded Customer's Back-Up Protection.
(iv) For connections with the National Electricity Transmission System at 400kV or
275kV, the Back-Up Protection will be provided by the Network Operator or
Non-Embedded Customer, as the case may be, with a fault clearance time not
longer than 300ms for faults on the Network Operator’s or Non-Embedded
Customer's Apparatus.
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(v) Such Protection will also be required to withstand, without tripping, the loading
incurred during the clearance of a fault on the National Electricity Transmission
System by breaker fail Protection at 400kV or 275kV. This will permit
Discrimination between Network Operator’s Back-Up Protection or NonEmbedded Customer’s Back-Up Protection, as the case may be, and Back-Up
Protection provided on the National Electricity Transmission System and other
User Systems. The requirement for and level of Discrimination required will be
specified in the Bilateral Agreement.
(c) (i)
Where the Network Operator or Non-Embedded Customer is connected to the
National Electricity Transmission System at 400kV or 275kV, and in Scotland
also at 132kV, and a circuit breaker is provided by the Network Operator or NonEmbedded Customer, or NGET, as the case may be, to interrupt the interchange
of fault current with the National Electricity Transmission System or the System
of the Network Operator or Non-Embedded Customer, as the case may be,
circuit breaker fail Protection will be provided by the Network Operator or NonEmbedded Customer, or NGET, as the case may be, on this circuit breaker.
(ii)
In the event, following operation of a Protection system, of a failure to interrupt
fault current by these circuit-breakers within the Fault Current Interruption Time,
the circuit breaker fail Protection is required to initiate tripping of all the necessary
electrically adjacent circuit-breakers so as to interrupt the fault current within the
next 200ms.
(d) The target performance for the System Fault Dependability Index shall be not less
than 99%. This is a measure of the ability of Protection to initiate successful tripping of
circuit breakers which are associated with the faulty items of Apparatus.
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CC.6.2.3.2
Fault Disconnection Facilities
(a) Where no Transmission circuit breaker is provided at the User's connection voltage,
the User must provide NGET with the means of tripping all the User's circuit breakers
necessary to isolate faults or System abnormalities on the National Electricity
Transmission System. In these circumstances, for faults on the User's System, the
User's Protection should also trip higher voltage Transmission circuit breakers.
These tripping facilities shall be in accordance with the requirements specified in the
Bilateral Agreement.
(b) NGET may require the installation of a System to Generator Operational
Intertripping Scheme in order to enable the timely restoration of circuits following
power System fault(s). These requirements shall be set out in the relevant Bilateral
Agreement.
CC.6.2.3.3
Automatic Switching Equipment
Where automatic reclosure of Transmission circuit breakers is required following faults on
the User's System, automatic switching equipment shall be provided in accordance with the
requirements specified in the Bilateral Agreement.
CC.6.2.3.4
Relay Settings
Protection and relay settings will be co-ordinated (both on connection and subsequently)
across the Connection Point in accordance with the Bilateral Agreement to ensure
effective disconnection of faulty Apparatus.
CC.6.2.3.5
Work on Protection equipment
Where a Transmission Licensee owns the busbar at the Connection Point, no busbar
Protection, mesh corner Protection relays, AC or DC wiring (other than power supplies or
DC tripping associated with the Network Operator or Non-Embedded Customer’s
Apparatus itself) may be worked upon or altered by the Network Operator or NonEmbedded Customer personnel in the absence of a representative of NGET or in Scotland,
a representative of NGET, or written authority from NGET to perform such work or
alterations in the absence of a representative of NGET.
CC.6.2.3.6
Equipment to be provided
CC.6.2.3.6.1
Protection of Interconnecting Connections
The requirements for the provision of Protection equipment for interconnecting connections
will be specified in the Bilateral Agreement.
CC.6.3
GENERAL GENERATING UNIT (AND OTSDUW) REQUIREMENTS
CC.6.3.1
This section sets out the technical and design criteria and performance requirements for
Generating Units, DC Converters and Power Park Modules (whether directly connected
to the National Electricity Transmission System or Embedded) and (where provided in
this section) OTSDUW Plant and Apparatus which each Generator or DC Converter
Station owner must ensure are complied with in relation to its Generating Units, DC
Converters and Power Park Modules and OTSDUW Plant and Apparatus but does not
apply to Small Power Stations or individually to Power Park Units. References to
Generating Units, DC Converters and Power Park Modules in this CC.6.3 should be read
accordingly. The performance requirements that OTSDUW Plant and Apparatus must be
capable of providing at the Interface Point under this section may be provided using a
combination of Generator Plant and Apparatus and/or OTSDUW Plant and Apparatus.
Plant Performance Requirements
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CC.6.3.2
(a) When supplying Rated MW all Onshore Synchronous Generating Units must be
capable of continuous operation at any point between the limits 0.85 Power Factor
lagging and 0.95 Power Factor leading at the Onshore Synchronous Generating
Unit terminals. At Active Power output levels other than Rated MW, all Onshore
Synchronous Generating Units must be capable of continuous operation at any point
between the Reactive Power
capability limits identified on the Generator
Performance Chart.
In addition to the above paragraph, where Onshore Synchronous Generating Unit(s):
(i)
have a Connection Entry Capacity which has been increased above Rated MW
(or the Connection Entry Capacity of the CCGT module has increased above
the sum of the Rated MW of the Generating Units compromising the CCGT
st
module), and such increase takes effect after 1 May 2009, the minimum lagging
Reactive Power capability at the terminals of the Onshore Synchronous
Generating Unit(s) must be 0.9 Power Factor at all Active Power output levels in
excess of Rated MW. Further, the User shall comply with the provisions of and
any instructions given pursuant to BC1.8 and the relevant Bilateral Agreement; or
(ii)
have a Connection Entry Capacity in excess of Rated MW (or the Connection
Entry Capacity of the CCGT module exceeds the sum of Rated MW of the
Generating Units comprising the CCGT module) and a Completion Date before
st
1 May 2009, alternative provisions relating to Reactive Power capability may be
specified in the Bilateral Agreement and where this is the case such provisions
must be complied with.
The short circuit ratio of Onshore Synchronous Generating Units with an Apparent
Power rating of less than 1600MVA shall be not less than 0.5. The short circuit ratio of
Onshore Synchronous Generating Units with a rated Apparent Power of 1600MVA
or above shall be not less than 0.4.
(b) Subject to paragraph (c) below, all Onshore Non-Synchronous Generating Units,
Onshore DC Converters and Onshore Power Park Modules must be capable of
maintaining zero transfer of Reactive Power at the Onshore Grid Entry Point (or User
System Entry Point if Embedded) at all Active Power output levels under steady
state voltage conditions. For Onshore Non-Synchronous Generating Units and
Onshore Power Park Modules the steady state tolerance on Reactive Power transfer
to and from the National Electricity Transmission System expressed in MVAr shall
be no greater than 5% of the Rated MW. For Onshore DC Converters the steady
state tolerance on Reactive Power transfer to and from the National Electricity
Transmission System shall be specified in the Bilateral Agreement.
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(c) Subject to the provisions of CC.6.3.2(d) below, all Onshore Non-Synchronous
Generating Units, Onshore DC Converters (excluding current source technology) and
Onshore Power Park Modules (excluding those connected to the Total System by a
current source Onshore DC Converter) and OTSDUW Plant and Apparatus at the
Interface Point with a Completion Date on or after 1 January 2006 must be capable of
supplying Rated MW output or Interface Point Capacity in the case of OTSDUW Plant
and Apparatus at any point between the limits 0.95 Power Factor lagging and 0.95
Power Factor leading at the Onshore Grid Entry Point in England and Wales or
Interface Point in the case of OTSDUW Plant and Apparatus or at the HV side of the
33/132kV or 33/275kV or 33/400kV transformer for Generators directly connected to
the Onshore Transmission System in Scotland (or User System Entry Point if
Embedded). With all Plant in service, the Reactive Power limits defined at Rated MW
or Interface Point Capacity in the case of OTSDUW Plant and Apparatus at Lagging
Power Factor will apply at all Active Power output levels above 20% of the Rated MW
or Interface Point Capacity in the case of OTSDUW Plant and Apparatus output as
defined in Figure 1. With all Plant in service, the Reactive Power limits defined at
Rated MW at Leading Power Factor will apply at all Active Power output levels above
50% of the Rated MW output or Interface Point Capacity in the case of OTSDUW
Plant and Apparatus as defined in Figure 1. With all Plant in service, the Reactive
Power limits will reduce linearly below 50% Active Power output as shown in Figure 1
unless the requirement to maintain the Reactive Power limits defined at Rated MW or
Interface Point Capacity in the case of OTSDUW Plant and Apparatus at Leading
Power Factor down to 20% Active Power output is specified in the Bilateral
Agreement. These Reactive Power limits will be reduced pro rata to the amount of
Plant in service.
Figure 1
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Point A is equivalent
(in MVAr) to
0.95 leading Power Factor at Rated MW output or Interface Point
Capacity in the case of OTSDUW Plant and Apparatus
Point B is equivalent
(in MVAr) to:
0.95 lagging Power Factor at Rated MW output or Interface Point
Capacity in the case of OTSDUW Plant and Apparatus
Point C is equivalent
(in MVAr) to:
-5% of Rated MW output or Interface Point Capacity in the case
of OTSDUW Plant and Apparatus
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Point D is equivalent
(in MVAr) to:
+5% of Rated MW output or Interface Point Capacity in the case
of OTSDUW Plant and Apparatus
Point E is equivalent
(in MVAr) to:
-12% of Rated MW output or Interface Point Capacity in the case
of OTSDUW Plant and Apparatus
(d) All Onshore Non-Synchronous Generating Units and Onshore Power Park
Modules in Scotland with a Completion Date after 1 April 2005 and before 1 January
2006 must be capable of supplying Rated MW at the range of power factors either:
(i)
from 0.95 lead to 0.95 lag as illustrated in Figure 1 at the User System Entry
Point for Embedded Generators or at the HV side of the 33/132kV or 33/275kV or
33/400kV transformer for Generators directly connected to the
Onshore
Transmission System. With all Plant in service, the Reactive Power limits
defined at Rated MW will apply at all Active Power output levels above 20% of the
Rated MW output as defined in Figure 1. These Reactive Power limits will be
reduced pro rata to the amount of Plant in service, or
(ii)
from 0.95 lead to 0.90 lag at the Onshore Non-Synchronous Generating Unit
(including Power Park Unit) terminals. For the avoidance of doubt Generators
complying with this option (ii) are not required to comply with CC.6.3.2(b).
(e) The short circuit ratio of Offshore Synchronous Generating Units at a Large Power
Station shall be not less than 0.5. At a Large Power Station all Offshore Synchronous
Generating Units, Offshore Non-Synchronous Generating Units, Offshore DC
Converters and Offshore Power Park Modules must be capable of maintaining:
(i)
zero transfer of Reactive Power at the Offshore Grid Entry Point for all
Generators with an Offshore Grid Entry Point at the LV Side of the Offshore
Platform at all Active Power output levels under steady state voltage conditions.
The steady state tolerance on Reactive Power transfer to and from an Offshore
Transmission System expressed in MVAr shall be no greater than 5% of the
Rated MW, or
(ii)
a transfer of Reactive Power at the Offshore Grid Entry Point at a value
specified in the Bilateral Agreement that will be equivalent to zero at the LV Side
of the Offshore Platform. In addition, the steady state tolerance on Reactive
Power transfer to and from an Offshore Transmission System expressed in
MVAr at the LV Side of the Offshore Platform shall be no greater than 5% of the
Rated MW, or
(iii) the Reactive Power capability (within associated steady state tolerance) specified
in the Bilateral Agreement if any alternative has been agreed with the Generator,
Offshore Transmission Licensee and NGET.
(f)
CC.6.3.3
In addition, a Genset shall meet the operational requirements as specified in BC2.A.2.6.
Each Generating Unit, DC Converter (including an OTSDUW DC Converter), Power Park
Module and/or CCGT Module must be capable of:
(a) continuously maintaining constant Active Power output for System Frequency
changes within the range 50.5 to 49.5 Hz; and
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(b) (subject to the provisions of CC.6.1.3) maintaining its Active Power output at a level not
lower than the figure determined by the linear relationship shown in Figure 2 for System
Frequency changes within the range 49.5 to 47 Hz, such that if the System Frequency
drops to 47 Hz the Active Power output does not decrease by more than 5%. In the
case of a CCGT Module, the above requirement shall be retained down to the Low
Frequency Relay trip setting of 48.8 Hz, which reflects the first stage of the Automatic
Low Frequency Demand Disconnection scheme notified to Network Operators
under OC6.6.2. For System Frequency below that setting, the existing requirement
shall be retained for a minimum period of 5 minutes while System Frequency remains
below that setting, and special measure(s) that may be required to meet this
requirement shall be kept in service during this period. After that 5 minutes period, if
System Frequency remains below that setting, the special measure(s) must be
discontinued if there is a materially increased risk of the Gas Turbine tripping. The
need for special measure(s) is linked to the inherent Gas Turbine Active Power output
reduction caused by reduced shaft speed due to falling System Frequency.
Figure 2
(c) For the avoidance of doubt in the case of a Generating Unit or Power Park Module (or
OTSDUW DC Converters at the Interface Point) using an Intermittent Power Source
where the mechanical power input will not be constant over time, the requirement is that
the Active Power output shall be independent of System Frequency under (a) above
and should not drop with System Frequency by greater than the amount specified in
(b) above.
(d) A DC Converter Station must be capable of maintaining its Active Power input (i.e.
when operating in a mode analogous to Demand) from the National Electricity
Transmission System (or User System in the case of an Embedded DC Converter
Station) at a level not greater than the figure determined by the linear relationship
shown in Figure 3 for System Frequency changes within the range 49.5 to 47 Hz, such
that if the System Frequency drops to 47.8 Hz the Active Power input decreases by
more than 60%.
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47
47.8
Frequency (Hz)
49.5
52.0
100% of Active
Power Input
40% of Active
Power Input
Figure 3
(e) At a Large Power Station, in the case of an Offshore Generating Unit, Offshore
Power Park Module, Offshore DC Converter and OTSDUW DC Converter, the
Generator shall comply with the requirements of CC.6.3.3. Generators should be
aware that Section K of the STC places requirements on Offshore Transmission
Licensees which utilise a Transmission DC Converter as part of their Offshore
Transmission System to make appropriate provisions to enable Generators to fulfil
their obligations.
(f)
CC.6.3.4
In the case of an OTSDUW DC Converter the OTSDUW Plant and Apparatus shall
provide a continuous signal indicating the real time frequency measured at the
Interface Point to the Offshore Grid Entry Point.
At the Grid Entry Point, the Active Power output under steady state conditions of any
Generating Unit, DC Converter or Power Park Module directly connected to the National
Electricity Transmission System or in the case of OTSDUW, the Active Power transfer at
the Interface Point, under steady state conditions of any OTSDUW Plant and Apparatus
should not be affected by voltage changes in the normal operating range specified in
paragraph CC.6.1.4 by more than the change in Active Power losses at reduced or
increased voltage. In addition:
(a) For any Onshore Generating Unit, Onshore DC Converter and Onshore Power
Park Module or OTSDUW the Reactive Power output under steady state conditions
should be fully available within the voltage range 5% at 400kV, 275kV and 132kV and
lower voltages, except for an Onshore Power Park Module or Onshore NonSynchronous Generating Unit if Embedded at 33kV and below (or directly connected
to the Onshore Transmission System at 33kV and below) where the requirement
shown in Figure 4 applies.
(b) At a Large Power Station, in the case of an Offshore Generating Unit, Offshore DC
Converter and Offshore Power Park Module where an alternative reactive capability
has been agreed with the Generator, as specified in CC.6.3.2(e) (iii), the voltage /
Reactive Power requirement shall be specified in the Bilateral Agreement. The
Reactive Power output under steady state conditions shall be fully available within the
voltage range 5% at 400kV, 275kV and 132kV and lower voltages.
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Voltage at an Onshore Grid Entry Point or User System Entry Point if Embedded
(% of Nominal) at 33 kV and below
105%
100%
95%
Power Factor 0.95 Lead at Rated 1.0
MW output or Onshore Grid
Entry Point equivalent Power
Factor if connected to the
Onshore Transmission System
in Scotland
Power Factor 0.95 lag at Rated MW
output or Onshore Grid Entry Point
equivalent Power Factor if connected
to the Onshore Transmission
System in Scotland or optionally in
Scotland for Plant with a Completion
Date before 1 January 2006 Power
Factor 0.9 lag at an Onshore Nonsynchronous Generating Unit or
Onshore Power Park Unit Terminals
Figure 4
CC.6.3.5
It is an essential requirement that the National Electricity Transmission System must
incorporate a Black Start Capability. This will be achieved by agreeing a Black Start
Capability at a number of strategically located Power Stations. For each Power Station
NGET will state in the Bilateral Agreement whether or not a Black Start Capability is
required.
Control Arrangements
CC.6.3.6
(a) Each:
(i)
Offshore Generating Unit in a Large Power Station or Onshore Generating
Unit; or,
(ii)
Onshore DC Converter with a Completion Date on or after 1 April 2005 or
Offshore DC Converter at a Large Power Station; or,
(iii) Onshore Power Park Module in England and Wales with a Completion Date on
or after 1 January 2006; or,
(iv) Onshore Power Park Module in operation in Scotland on or after 1 January 2006
(with a Completion Date after 1 July 2004 and in a Power Station with a
Registered Capacity of 50MW or more); or,
(v) Offshore Power Park Module in a Large Power Station with a Registered
Capacity of 50MW or more;
must be capable of contributing to Frequency control by continuous modulation of
Active Power supplied to the National Electricity Transmission System or the User
System in which it is Embedded. For the avoidance of doubt each OTSDUW DC
Converter shall provide each User in respect of its Offshore Power Stations
connected to and/or using an Offshore Transmission System a continuous signal
indicating the real time Frequency measured at the Transmission Interface Point.
(b) Each:
(i)
Onshore Generating Unit; or,
(ii)
Onshore DC Converter (with a Completion Date on or after 1 April 2005
excluding current source technologies); or
(iii) Onshore Power Park Module in England and Wales with a Completion Date on
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or after 1 January 2006; or,
(iv) Onshore Power Park Module in Scotland irrespective of Completion Date; or,
(v) Offshore Generating Unit at a Large Power Station, Offshore DC Converter at
a Large Power Station or Offshore Power Park Module at a Large Power
Station which provides a reactive range beyond the minimum requirements
specified in CC.6.3.2(e) (iii); or,
(vi) OTSDUW Plant and Apparatus at a Transmission Interface Point
must be capable of contributing to voltage control by continuous changes to the
Reactive Power supplied to the National Electricity Transmission System or the
User System in which it is Embedded.
CC.6.3.7
(a) Each Generating Unit, DC Converter or Power Park Module (excluding Onshore
Power Park Modules in Scotland with a Completion Date before 1 July 2004 or
Onshore Power Park Modules in a Power Station in Scotland with a Registered
Capacity less than 50MW or Offshore Power Park Modules in a Large Power
Station located Offshore with a Registered Capacity less than 50MW) must be fitted
with a fast acting proportional Frequency control device (or turbine speed governor)
and unit load controller or equivalent control device to provide Frequency response
under normal operational conditions in accordance with Balancing Code 3 (BC3). In
the case of a Power Park Module the Frequency or speed control device(s) may be on
the Power Park Module or on each individual Power Park Unit or be a combination of
both. The Frequency control device(s) (or speed governor(s)) must be designed and
operated to the appropriate:
(i)
European Specification; or
(ii)
in the absence of a relevant European Specification, such other standard which
is in common use within the European Community (which may include a
manufacturer specification);
as at the time when the installation of which it forms part was designed or (in the case of
modification or alteration to the Frequency control device (or turbine speed governor))
when the modification or alteration was designed.
The European Specification or other standard utilised in accordance with subparagraph CC.6.3.7 (a) (ii) will be notified to NGET by the Generator or DC Converter
Station owner or, in the case of an Embedded Medium Power Station not subject to a
Bilateral Agreement or Embedded DC Converter Station not subject to a Bilateral
Agreement, the relevant Network Operator:
(i)
as part of the application for a Bilateral Agreement; or
(ii)
as part of the application for a varied Bilateral Agreement; or
(iii) in the case of an Embedded Development, within 28 days of entry into the
Embedded Development Agreement (or such later time as agreed with NGET);
or
(iv) as soon as possible prior to any modification or alteration to the Frequency control
device (or governor); and
(b) The Frequency control device (or speed governor) in co-ordination with other control
devices must control the Generating Unit, DC Converter or Power Park Module
Active Power Output with stability over the entire operating range of the Generating
Unit, DC Converter or Power Park Module; and
(c) The Frequency control device (or speed governor) must meet the following minimum
requirements:
(i)
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Where a Generating Unit, DC Converter or Power Park Module becomes
isolated from the rest of the Total System but is still supplying Customers, the
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Frequency control device (or speed governor) must also be able to control
System Frequency below 52Hz unless this causes the Generating Unit, DC
Converter or Power Park Module to operate below its Designed Minimum
Operating Level when it is possible that it may, as detailed in BC 3.7.3, trip after a
time. For the avoidance of doubt the Generating Unit, DC Converter or Power
Park Module is only required to operate within the System Frequency range 47 52 Hz as defined in CC.6.1.3;
(ii)
the Frequency control device (or speed governor) must be capable of being set so
that it operates with an overall speed Droop of between 3% and 5%. For the
avoidance of doubt, in the case of a Power Park Module the speed Droop should
be equivalent of a fixed setting between 3% and 5% applied to each Power Park
Unit in service;
(iii) in the case of all Generating Units, DC Converter or Power Park Module other
than the Steam Unit within a CCGT Module the Frequency control device (or
speed governor) deadband should be no greater than 0.03Hz (for the avoidance of
doubt, ±0.015Hz). In the case of the Steam Unit within a CCGT Module, the
speed Governor Deadband should be set to an appropriate value consistent with
the requirements of CC.6.3.7(c)(i) and the requirements of BC3.7.2 for the
provision of Limited High Frequency Response;
For the avoidance of doubt, the minimum requirements in (ii) and (iii) for the provision of
System Ancillary Services do not restrict the negotiation of Commercial Ancillary
Services between NGET and the User using other parameters; and
(d) A facility to modify, so as to fulfil the requirements of the Balancing Codes, the Target
Frequency setting either continuously or in a maximum of 0.05 Hz steps over at least
the range 50 0.1 Hz should be provided in the unit load controller or equivalent device.
(e) (i)
Each Onshore Generating Unit and/or CCGT Module which has a Completion
Date after 1 January 2001 in England and Wales, and after 1 April 2005 in
Scotland, must be capable of meeting the minimum Frequency response
requirement profile subject to and in accordance with the provisions of Appendix 3.
(ii)
Each DC Converter at a DC Converter Station which has a Completion Date on
or after 1 April 2005 and each Offshore DC Converter at a Large Power Station
must be capable of meeting the minimum Frequency response requirement profile
subject to and in accordance with the provisions of Appendix 3.
(iii) Each Onshore Power Park Module in operation in England and Wales with a
Completion Date on or after 1 January 2006 must be capable of meeting the
minimum Frequency response requirement profile subject to and in accordance
with the provisions of Appendix 3.
(iv) Each Onshore Power Park Module in operation on or after 1 January 2006 in
Scotland (with a Completion Date on or after 1 April 2005 and a Registered
Capacity of 50MW or more) must be capable of meeting the minimum Frequency
response requirement profile subject to and in accordance with the provisions of
Appendix 3.
(v) Each Offshore Generating Unit in a Large Power Station must be capable of
meeting the minimum Frequency response requirement profile subject to and in
accordance with the provisions of Appendix 3.
(vi) Each Offshore Power Park Module in a Large Power Station with a Registered
Capacity of 50 MW or greater, must be capable of meeting the minimum
Frequency response requirement profile subject to and in accordance with the
provisions of Appendix 3.
(vii) Subject to the requirements of CC.6.3.7(e), Offshore Generating Units at a Large
Power Station, Offshore Power Park Modules at a Large Power Station and
Offshore DC Converters in a Large Power Station shall comply with the
requirements of CC.6.3.7. Generators should be aware that Section K of the STC
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places requirements on Offshore Transmission Licensees which utilise a
Transmission DC Converter as part of their Offshore Transmission System to
make appropriate provisions to enable Generators to fulfil their obligations.
(viii) Each OTSDUW DC Converter must be capable of providing a continuous signal
indicating the real time frequency measured at the Interface Point to the Offshore
Grid Entry Point.
(f)
For the avoidance of doubt, the requirements of Appendix 3 do not apply to:
(i)
Generating Units and/or CCGT Modules which have a Completion Date before
1 January 2001 in England and Wales, and before 1 April 2005 in Scotland, for
whom the remaining requirements of this clause CC.6.3.7 shall continue to apply
unchanged: or
(ii)
DC Converters at a DC Converter Station which have a Completion Date before
1 April 2005; or
(iii) Onshore Power Park Modules in England and Wales with a Completion Date
before 1 January 2006 for whom only the requirements of Limited Frequency
Sensitive Mode (BC3.5.2) operation shall apply; or
(iv) Onshore Power Park Modules in operation in Scotland before 1 January 2006 for
whom only the requirements of Limited Frequency Sensitive Mode (BC3.5.2)
operation shall apply; or
(v) Onshore Power Park Modules in operation after 1 January 2006 in Scotland
which have a Completion Date before 1 April 2005 for whom the remaining
requirements of this clause CC.6.3.7 shall continue to apply unchanged; or
(vi) Offshore Power Park Modules which are in a Large Power Station with a
Registered Capacity less than 50MW for whom only the requirements of Limited
Frequency Sensitive Mode (BC3.5.2) operation shall apply; or
Excitation and Voltage Control Performance Requirements
CC.6.3.8
(a) Excitation and voltage control performance requirements applicable to Onshore
Generating Units, Onshore Power Park Modules, Onshore DC Converters and
OTSDUW Plant and Apparatus.
(i)
A continuously-acting automatic excitation control system is required to provide
constant terminal voltage control of the Onshore Synchronous Generating Unit
without instability over the entire operating range of the Onshore Generating Unit.
(ii)
In respect of Onshore Synchronous Generating Units with a Completion Date
before 1 January 2009, the requirements for excitation control facilities, including
Power System Stabilisers, where in NGET's view these are necessary for system
reasons, will be specified in the Bilateral Agreement. If any Modification to the
excitation control facilities of such Onshore Synchronous Generating Units is
made on or after 1 January 2009 the requirements that shall apply may be
specified in the Bilateral Agreement as varied. To the extent that the Bilateral
Agreement does not specify, the requirements given or referred to in CC.A.6 shall
apply. The performance requirements for a continuously acting automatic
excitation control system that shall be complied with by the User in respect of such
Onshore Synchronous Generating Units with a Completion Date on or after 1
January 2009 are given or referred to in CC.A.6. Reference is made to on-load
commissioning witnessed by NGET in BC2.11.2.
(iii) In the case of an Onshore Non-Synchronous Generating Unit, Onshore DC
Converter, Onshore Power Park Module or OTSDUW Plant and Apparatus at
the Interface Point a continuously-acting automatic control system is required to
provide control of the voltage (or zero transfer of Reactive Power as applicable to
CC.6.3.2) at the Onshore Grid Entry Point or User System Entry Point or in the
case of OTSDUW Plant and Apparatus at the Interface Point without instability
over the entire operating range of the Onshore Non-Synchronous Generating
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Unit, Onshore DC Converter, Onshore Power Park Module or OTSDUW Plant
and Apparatus. Any Plant or Apparatus used in the provisions of such voltage
control within an Onshore Power Park Module may be located at the Power Park
Unit terminals, an appropriate intermediate busbar or the Connection Point.
OTSDUW Plant and Apparatus used in the provision of such voltage control may
be located at the Offshore Grid Entry Point, an appropriate intermediate busbar
or at the Interface Point. In the case of an Onshore Power Park Module in
Scotland with a Completion Date before 1 January 2009, voltage control may be
at the Power Park Unit terminals, an appropriate intermediate busbar or the
Connection Point as specified in the Bilateral Agreement. When operating below
20% Rated MW the automatic control system may continue to provide voltage
control utilising any available reactive capability. If voltage control is not being
provided the automatic control system shall be designed to ensure a smooth
transition between the shaded area bound by CD and the non shaded area bound
by AB in Figure 1 of CC.6.3.2 (c).
(iv) The performance requirements for a continuously acting automatic voltage control
system in respect of Onshore Power Park Modules, Onshore NonSynchronous Generating Units and Onshore DC Converters with a
Completion Date before 1 January 2009 will be specified in the Bilateral
Agreement. If any Modification to the continuously acting automatic voltage
control system of such Onshore Power Park Modules, Onshore NonSynchronous Generating Units and Onshore DC Converters is made on or
after 1 January 2009 the requirements that shall apply may be specified in the
Bilateral Agreement as varied. To the extent that the Bilateral Agreement does
not specify, the requirements given or referred to in CC.A.7 shall apply. The
performance requirements for a continuously acting automatic voltage control
system that shall be complied with by the User in respect of Onshore Power Park
Modules, Onshore Non-Synchronous Generating Units and Onshore DC
Converters or OTSDUW Plant and Apparatus at the Interface Point with a
Completion Date on or after 1 January 2009 are given or referred to in CC.A.7.
(v) Unless otherwise required for testing in accordance with OC5.A.2, the automatic
excitation control system of an Onshore Synchronous Generating Unit shall
always be operated such that it controls the Onshore Synchronous Generating
Unit terminal voltage to a value that is
-
equal to its rated value; or
only where provisions have been made in the Bilateral Agreement, greater than
its rated value.
(vi) In particular, other control facilities, including constant Reactive Power output
control modes and constant Power Factor control modes (but excluding VAR
limiters) are not required. However, if present in the excitation or voltage control
system they will be disabled unless the Bilateral Agreement records otherwise.
Operation of such control facilities will be in accordance with the provisions
contained in BC2.
(b) Excitation and voltage control performance requirements applicable to Offshore
Generating Units at a Large Power Station, Offshore Power Park Modules at a
Large Power Station and Offshore DC Converters at a Large Power Station.
A continuously acting automatic control system is required to provide either:
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(i)
control of Reactive Power (as specified in CC.6.3.2(e) (i) (ii)) at the Offshore Grid
Entry Point without instability over the entire operating range of the Offshore
Generating Unit, Offshore DC Converter or Offshore Power Park Module. The
performance requirements for this automatic control system will be specified in the
Bilateral Agreement or;
(ii)
where an alternative reactive capability has been specified in the Bilateral
Agreement, in accordance with CC.6.3.2 (e) (iii), the Offshore Generating Unit,
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Offshore Power Park Module or Offshore DC Converter will be required to
control voltage and / or Reactive Power without instability over the entire operating
range of the Offshore Generating Unit, Offshore Power Park Module or
Offshore DC Converter. The performance requirements of the control system will
be specified in the Bilateral Agreement.
In addition to CC.6.3.8(b) (i) and (ii) the requirements for excitation control facilities,
including Power System Stabilisers, where in NGET’s view these are necessary for
system reasons, will be specified in the Bilateral Agreement. Reference is made to onload commissioning witnessed by NGET in BC2.11.2.
Steady state Load Inaccuracies
CC.6.3.9
The standard deviation of Load error at steady state Load over a 30 minute period must not
exceed 2.5 per cent of a Genset’s Registered Capacity. Where a Genset is instructed to
Frequency sensitive operation, allowance will be made in determining whether there has
been an error according to the governor droop characteristic registered under the PC.
For the avoidance of doubt in the case of a Power Park Module allowance will be made for
the full variation of mechanical power output.
Negative Phase Sequence Loadings
CC.6.3.10
In addition to meeting the conditions specified in CC.6.1.5(b), each Synchronous
Generating Unit will be required to withstand, without tripping, the negative phase sequence
loading incurred by clearance of a close-up phase-to-phase fault, by System Back-Up
Protection on the National Electricity Transmission System or User System located
Onshore in which it is Embedded.
Neutral Earthing
CC.6.3.11
At nominal System voltages of 132kV and above the higher voltage windings of a
transformer of a Generating Unit, DC Converter, Power Park Module or transformer
resulting from OTSDUW must be star connected with the star point suitable for connection to
earth. The earthing and lower voltage winding arrangement shall be such as to ensure that
the Earth Fault Factor requirement of paragraph CC.6.2.1.1 (b) will be met on the National
Electricity Transmission System at nominal System voltages of 132kV and above.
Frequency Sensitive Relays
CC.6.3.12
As stated in CC.6.1.3, the System Frequency could rise to 52Hz or fall to 47Hz. Each
Generating Unit, DC Converter, OTSDUW Plant and Apparatus, Power Park Module or
any constituent element must continue to operate within this Frequency range for at least
the periods of time given in CC.6.1.3 unless NGET has agreed to any Frequency-level
relays and/or rate-of-change-of-Frequency relays which will trip such Generating Unit, DC
Converter, OTSDUW Plant and Apparatus, Power Park Module and any constituent
element within this Frequency range, under the Bilateral Agreement.
CC.6.3.13
Generators (including in respect of OTSDUW Plant and Apparatus) and DC Converter
Station owners will be responsible for protecting all their Generating Units (and OTSDUW
Plant and Apparatus), DC Converters or Power Park Modules against damage should
Frequency excursions outside the range 52Hz to 47Hz ever occur. Should such excursions
occur, it is up to the Generator or DC Converter Station owner to decide whether to
disconnect his Apparatus for reasons of safety of Apparatus, Plant and/or personnel.
CC.6.3.14
It may be agreed in the Bilateral Agreement that a Genset shall have a Fast-Start
Capability. Such Gensets may be used for Operating Reserve and their Start-Up may be
initiated by Frequency-level relays with settings in the range 49Hz to 50Hz as specified
pursuant to OC2.
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CC.6.3.15
Fault Ride Through
This section sets out the fault ride through requirements on Generating Units, Power Park
Modules, DC Converters and OTSDUW Plant and Apparatus. Onshore Generating
Units, Onshore Power Park Modules, Onshore DC Converters (including Embedded
Medium Power Stations and Embedded DC Converter Stations not subject to a Bilateral
Agreement and with an Onshore User System Entry Point (irrespective of whether they
are located Onshore or Offshore)) and OTSDUW Plant and Apparatus are required to
operate through System faults and disturbances as defined in CC.6.3.15.1 (a), CC.6.3.15.1
(b) and CC.6.3.15.3. Offshore Generating Units at a Large Power Station, Offshore
Power Park Modules at a Large Power Station and Offshore DC Converters at a Large
Power Station shall have the option of meeting either:
(i)
CC.6.3.15.1 (a), CC.6.3.15.1 (b) and CC.6.3.15.3, or:
(ii)
CC.6.3.15.2 (a), CC.6.3.15.2 (b) and CC.6.3.15.3
Offshore Generators and Offshore DC Converter owners, should notify NGET which
option they wish to select within 28 days (or such longer period as NGET may agree, in any
event this being no later than 3 months before the Completion Date of the offer for a final
CUSC Contract which would be made following the appointment of the Offshore
Transmission Licensee).
CC.6.3.15.1
Fault Ride through applicable to Generating Units, Power Park Modules and DC Converters
and OTSDUW Plant and Apparatus
(a) Short circuit faults on the Onshore Transmission System (which may include an
Interface Point) at Supergrid Voltage up to 140ms in duration.
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(i)
Each Generating Unit, DC Converter, or Power Park Module and any
constituent Power Park Unit thereof and OTSDUW Plant and Apparatus shall
remain transiently stable and connected to the System without tripping of any
Generating Unit, DC Converter or Power Park Module and / or any constituent
Power Park Unit, OTSDUW Plant and Apparatus, and for Plant and Apparatus
installed on or after 1 December 2017, reactive compensation equipment, for a
close-up solid three-phase short circuit fault or any unbalanced short circuit fault on
the Onshore Transmission System (including in respect of OTSDUW Plant and
Apparatus, the Interface Point) operating at Supergrid Voltages for a total fault
clearance time of up to 140 ms. A solid three-phase or unbalanced earthed fault
results in zero voltage on the faulted phase(s) at the point of fault. The duration of
zero voltage is dependent on local Protection and circuit breaker operating times.
This duration and the fault clearance times will be specified in the Bilateral
Agreement. Following fault clearance, recovery of the Supergrid Voltage on the
Onshore Transmission System to 90% may take longer than 140ms as
illustrated in Appendix 4A Figures CC.A.4A.1 (a) and (b). It should be noted that in
the case of an Offshore Generating Unit, Offshore DC Converter or Offshore
Power Park Module (including any Offshore Power Park Unit thereof) which is
connected to an Offshore Transmission System which includes a Transmission
DC Converter as part of that Offshore Transmission System, the Offshore Grid
Entry Point voltage may not indicate the presence of a fault on the Onshore
Transmission System. The fault will affect the level of Active Power that can be
transferred to the Onshore Transmission System and therefore subject the
Offshore Generating Unit, Offshore DC Converter or Offshore Power Park
Module (including any Offshore Power Park Unit thereof) to a load rejection.
(ii)
Each Generating Unit, Power Park Module and OTSDUW Plant and Apparatus,
shall be designed such that upon both clearance of the fault on the Onshore
Transmission System as detailed in CC.6.3.15.1 (a) (i) and within 0.5 seconds of
the restoration of the voltage at the Onshore Grid Entry Point (for Onshore
Generating Units or Onshore Power Park Modules) or Interface Point (for
Offshore Generating Units, Offshore Power Park Modules or OTSDUW Plant
and Apparatus) to the minimum levels specified in CC.6.1.4 (or within 0.5
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seconds of restoration of the voltage at the User System Entry Point to 90% of
nominal or greater if Embedded), Active Power output or in the case of OTSDUW
Plant and Apparatus, Active Power transfer capability, shall be restored to at
least 90% of the level available immediately before the fault. Once the Active
Power output, or in the case of OTSDUW Plant and Apparatus, Active Power
transfer capability, has been restored to the required level, Active Power
oscillations shall be acceptable provided that:
-
the total Active Energy delivered during the period of the oscillations is at
least that which would have been delivered if the Active Power was constant
-
the oscillations are adequately damped
During the period of the fault as detailed in CC.6.3.15.1 (a) (i) for which the voltage
at the Grid Entry Point (or Interface Point in the case of OTSDUW Plant and
Apparatus) is outside the limits specified in CC.6.1.4, each Generating Unit or
Power Park Module or OTSDUW Plant and Apparatus shall generate maximum
reactive current without exceeding the transient rating limit of the Generating Unit,
OTSDUW Plant and Apparatus or Power Park Module and / or any constituent
Power Park Unit or reactive compensation equipment. For Plant and Apparatus
installed on or after 1 December 2017, switched reactive compensation equipment
(such as mechanically switched capacitors and reactors) shall be controlled such
that it is not switched in or out of service during the fault but may act to assist in
post fault voltage recovery.
(iii) Each DC Converter shall be designed to meet the Active Power recovery
characteristics (and OTSDUW DC Converter shall be designed to meet the Active
Power transfer capability at the Interface Point) as specified in the Bilateral
Agreement upon clearance of the fault on the Onshore Transmission System as
detailed in CC.6.3.15.1 (a) (i).
(b) Supergrid Voltage dips on the Onshore Transmission System greater than 140ms in
duration
(1b) Requirements applicable to Synchronous Generating Units subject to Supergrid
Voltage dips on the Onshore Transmission System greater than 140ms in duration.
In addition to the requirements of CC.6.3.15.1 (a) each Synchronous Generating Unit,
each with a Completion Date on or after 1 April 2005 shall:
(i)
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remain transiently stable and connected to the System without tripping of any
Synchronous Generating Unit for balanced Supergrid Voltage dips and
associated durations on the Onshore Transmission System (which could be at
the Interface Point) anywhere on or above the heavy black line shown in Figure
5a. Appendix 4A and Figures CC.A.4A.3.2 (a), (b) and (c) provide an explanation
and illustrations of Figure 5a; and,
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Figure 5a
(ii)
provide Active Power output at the Grid Entry Point, during Supergrid Voltage
dips on the Onshore Transmission System as described in Figure 5a, at least in
proportion to the retained balanced voltage at the Onshore Grid Entry Point (for
Onshore Synchronous Generating Units) or Interface Point (for Offshore
Synchronous Generating Units) (or the retained balanced voltage at the User
System Entry Point if Embedded) and shall generate maximum reactive current
(where the voltage at the Grid Entry Point is outside the limits specified in
CC.6.1.4) without exceeding the transient rating limits of the Synchronous
Generating Unit and,
(iii) restore Active Power output following Supergrid Voltage dips on the Onshore
Transmission System as described in Figure 5a, within 1 second of restoration of
the voltage to 1.0p.u of the nominal voltage at the:
Onshore Grid Entry Point for directly connected Onshore Synchronous
Generating Units or,
Interface Point for Offshore Synchronous Generating Units or,
User System Entry
Generating Units or,
Point
for
Embedded
Onshore
Synchronous
User System Entry Point for Embedded Medium Power Stations not
subject to a Bilateral Agreement which comprise Synchronous Generating
Units and with an Onshore User System Entry Point (irrespective of
whether they are located Onshore or Offshore)
to at least 90% of the level available immediately before the occurrence of the dip.
Once the Active Power output has been restored to the required level, Active
Power oscillations shall be acceptable provided that:
-
the total Active Energy delivered during the period of the oscillations is at
least that which would have been delivered if the Active Power was constant
-
the oscillations are adequately damped.
For the avoidance of doubt a balanced Onshore Transmission System Supergrid
Voltage meets the requirements of CC.6.1.5 (b) and CC.6.1.6.
(2b)
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Requirements applicable to OTSDUW Plant and Apparatus and Power Park Modules
subject to Supergrid Voltage dips on the Onshore Transmission System greater
than 140ms in duration
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In addition to the requirements of CC.6.3.15.1 (a) each OTSDUW Plant and Apparatus
or each Power Park Module and / or any constituent Power Park Unit, each with a
Completion Date on or after the 1 April 2005 shall:
(i)
remain transiently stable and connected to the System without tripping of any
OTSDUW Plant and Apparatus, or Power Park Module and / or any constituent
Power Park Unit, for balanced Supergrid Voltage dips and associated durations
on the Onshore Transmission System (which could be at the Interface Point)
anywhere on or above the heavy black line shown in Figure 5b. Appendix 4A and
Figures CC.A.4A.3.4 (a), (b) and (c) provide an explanation and illustrations of
Figure 5b; and,
90
85
Supergrid Voltage Level
(% of Nominal)
80
15
0.14s
1.2s
2.5s
3 minutes
Supergrid Voltage Duration
Figure 5b
(ii)
provide Active Power output at the Grid Entry Point or in the case of an
OTSDUW, Active Power transfer capability at the Transmission Interface Point,
during Supergrid Voltage dips on the Onshore Transmission System as
described in Figure 5b, at least in proportion to the retained balanced voltage at the
Onshore Grid Entry Point (for Onshore Power Park Modules) or Interface
Point (for OTSDUW Plant and Apparatus and Offshore Power Park Modules)
(or the retained balanced voltage at the User System Entry Point if Embedded)
except in the case of a Non-Synchronous Generating Unit or OTSDUW Plant
and Apparatus or Power Park Module where there has been a reduction in the
Intermittent Power Source or in the case of OTSDUW Active Power transfer
capability in the time range in Figure 5b that restricts the Active Power output or in
the case of an OTSDUW Active Power transfer capability below this level and
shall generate maximum reactive current (where the voltage at the Grid Entry
Point, or in the case of an OTSDUW Plant and Apparatus, the Interface Point
voltage, is outside the limits specified in CC.6.1.4) without exceeding the transient
rating limits of the OTSDUW Plant and Apparatus or Power Park Module and
any constituent Power Park Unit; and,
(iii) restore Active Power output (or, in the case of OTSDUW, Active Power transfer
capability), following Supergrid Voltage dips on the Onshore Transmission
System as described in Figure 5b, within 1 second of restoration of the voltage at
the:
Onshore Grid Entry Point for directly connected Onshore Power Park
Modules or,
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Interface Point for OTSDUW Plant and Apparatus and Offshore Power
Park Modules or,
User System Entry Point for Embedded Onshore Power Park Modules or,
User System Entry Point for Embedded Medium Power Stations which
comprise Power Park Modules not subject to a Bilateral Agreement and
with an Onshore User System Entry Point (irrespective of whether they are
located Onshore or Offshore)
to the minimum levels specified in CC.6.1.4 to at least 90% of the level available
immediately before the occurrence of the dip except in the case of a NonSynchronous Generating Unit, OTSDUW Plant and Apparatus or Power Park
Module where there has been a reduction in the Intermittent Power Source in
the time range in Figure 5b that restricts the Active Power output or, in the case of
OTSDUW, Active Power transfer capability below this level. Once the Active
Power output or, in the case of OTSDUW, Active Power transfer capability has
been restored to the required level, Active Power oscillations shall be acceptable
provided that:
-
the total Active Energy delivered during the period of the oscillations is at
least that which would have been delivered if the Active Power was constant
-
the oscillations are adequately damped.
For the avoidance of doubt a balanced Onshore Transmission System Supergrid
Voltage meets the requirements of CC.6.1.5 (b) and CC.6.1.6.
CC.6.3.15.2
Fault Ride Through applicable to Offshore Generating Units at a Large Power Station,
Offshore Power Park Modules at a Large Power Station and Offshore DC Converters at
a Large Power Station who choose to meet the fault ride through requirements at the LV
side of the Offshore Platform
(a) Requirements on Offshore Generating Units, Offshore Power Park Modules and
Offshore DC Converters to withstand voltage dips on the LV Side of the Offshore
Platform for up to 140ms in duration as a result of faults and / or voltage dips on the
Onshore Transmission System operating at Supergrid Voltage
(i)
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Each Offshore Generating Unit, Offshore DC Converter, or Offshore Power
Park Module and any constituent Power Park Unit thereof shall remain transiently
stable and connected to the System without tripping of any Offshore Generating
Unit, or Offshore DC Converter or Offshore Power Park Module and / or any
constituent Power Park Unit or, in the case of Plant and Apparatus installed on
or after 1 December 2017, reactive compensation equipment, for any balanced or
unbalanced voltage dips on the LV Side of the Offshore Platform whose profile is
anywhere on or above the heavy black line shown in Figure 6. For the avoidance of
doubt, the profile beyond 140ms in Figure 6 shows the minimum recovery in
voltage that will be seen by the generator following clearance of the fault at 140ms.
Appendix 4B and Figures CC.A.4B.2 (a) and (b) provide further illustration of the
voltage recovery profile that may be seen. It should be noted that in the case of an
Offshore Generating Unit, Offshore DC Converter or Offshore Power Park
Module (including any Offshore Power Park Unit thereof) which is connected to
an Offshore Transmission System which includes a Transmission DC
Converter as part of that Offshore Transmission System, the Offshore Grid
Entry Point voltage may not indicate the presence of a fault on the Onshore
Transmission System. The voltage dip will affect the level of Active Power that
can be transferred to the Onshore Transmission System and therefore subject
the Offshore Generating Unit, Offshore DC Converter or Offshore Power Park
Module (including any Offshore Power Park Unit thereof) to a load rejection.
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V/VN(%)
100%
94%
60%
15%
0
140ms
500ms
Time
Figure 6
V/VN is the ratio of the actual voltage on one or more phases at the LV Side of the
Offshore Platform to the nominal voltage of the LV Side of the Offshore
Platform.
(ii)
Each Offshore Generating Unit, or Offshore Power Park Module and any
constituent Power Park Unit thereof shall provide Active Power output, during
voltage dips on the LV Side of the Offshore Platform as described in Figure 6, at
least in proportion to the retained voltage at the LV Side of the Offshore Platform
except in the case of an Offshore Non-Synchronous Generating Unit or
Offshore Power Park Module where there has been a reduction in the
Intermittent Power Source in the time range in Figure 6 that restricts the Active
Power output below this level and shall generate maximum reactive current
without exceeding the transient rating limits of the Offshore Generating Unit or
Offshore Power Park Module and any constituent Power Park Unit or, in the
case of Plant and Apparatus installed on or after 1 December 2017, reactive
compensation equipment. Once the Active Power output has been restored to the
required level, Active Power oscillations shall be acceptable provided that:
-
the total Active Energy delivered during the period of the oscillations is at
least that which would have been delivered if the Active Power was constant
-
the oscillations are adequately damped
and;
(iii) Each Offshore DC Converter shall be designed to meet the Active Power
recovery characteristics as specified in the Bilateral Agreement upon restoration
of the voltage at the LV Side of the Offshore Platform.
(b)
Requirements of Offshore Generating Units, Offshore Power Park Modules,
to
withstand voltage dips on the LV Side of the Offshore Platform greater than 140ms in
duration.
(1b)
Requirements applicable to Offshore Synchronous Generating Units to withstand
voltage dips on the LV Side of the Offshore Platform greater than 140ms in duration.
In addition to the requirements of CC.6.3.15.2. (a) each Offshore Synchronous
Generating Unit shall:
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(i)
remain transiently stable and connected to the System without tripping of any
Offshore Synchronous Generating Unit for any balanced voltage dips on the LV
side of the Offshore Platform and associated durations anywhere on or above
the heavy black line shown in Figure 7a. Appendix 4B and Figures CC.A.4B.3.2
(a), (b) and (c) provide an explanation and illustrations of Figure 7a. It should be
noted that in the case of an Offshore Synchronous Generating Unit which is
connected to an Offshore Transmission System which includes a Transmission
DC Converter as part of that Offshore Transmission System, the Offshore Grid
Entry Point voltage may not indicate the presence of a voltage dip on the
Onshore Transmission System. The voltage dip will affect the level of Active
Power that can be transferred to the Onshore Transmission System and
therefore subject the Offshore Generating Unit, to a load rejection.
(ii)
provide Active Power output, during voltage dips on the LV Side of the Offshore
Platform as described in Figure 7a, at least in proportion to the retained balanced
or unbalanced voltage at the LV Side of the Offshore Platform and shall
generate maximum reactive current (where the voltage at the Offshore Grid Entry
Point is outside the limits specified in CC.6.1.4) without exceeding the transient
rating limits of the Offshore Synchronous Generating Unit and,
(iii) within 1 second of restoration of the voltage to 1.0p.u of the nominal voltage at the
LV Side of the Offshore Platform, restore Active Power to at least 90% of the
Offshore Synchronous Generating Unit's immediate pre-disturbed value, unless
there has been a reduction in the Intermittent Power Source in the time range in
Figure 7a that restricts the Active Power output below this level. Once the Active
Power output has been restored to the required level, Active Power oscillations
shall be acceptable provided that:
-
the total Active Energy delivered during the period of the oscillations is at
least that which would have been delivered if the Active Power was constant
-
the oscillations are adequately damped
(2b) Requirements applicable to Offshore Power Park Modules to withstand voltage dips
on the LV Side of the Offshore Platform greater than 140ms in duration.
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In addition to the requirements of CC.6.3.15.2. (a) each Offshore Power Park Module
and / or any constituent Power Park Unit, shall:
(i)
remain transiently stable and connected to the System without tripping of any
Offshore Power Park Module and / or any constituent Power Park Unit, for any
balanced voltage dips on the LV side of the Offshore Platform and associated
durations anywhere on or above the heavy black line shown in Figure 7b. Appendix
4B and Figures CC.A.4B.5. (a), (b) and (c) provide an explanation and illustrations
of Figure 7b. It should be noted that in the case of an Offshore Power Park
Module (including any Offshore Power Park Unit thereof) which is connected to
an Offshore Transmission System which includes a Transmission DC
Converter as part of that Offshore Transmission System, the Offshore Grid
Entry Point voltage may not indicate the presence of a voltage dip on the
Onshore Transmission System. The voltage dip will affect the level of Active
Power that can be transferred to the Onshore Transmission System and
therefore subject the Offshore Power Park Module (including any Offshore
Power Park Unit thereof) to a load rejection.
90
Voltage at LV Side of Offshore Platform
(% of Nominal)
85
80
15
0.14s
1.2s
2.5s
3 minutes
Offshore Platform LV Voltage Duration
Figure 7b
(ii)
provide Active Power output, during voltage dips on the LV Side of the Offshore
Platform as described in Figure 7b, at least in proportion to the retained balanced
or unbalanced voltage at the LV Side of the Offshore Platform except in the case
of an Offshore Non-Synchronous Generating Unit or Offshore Power Park
Module where there has been a reduction in the Intermittent Power Source in
the time range in Figure 7b that restricts the Active Power output below this level
and shall generate maximum reactive current (where the voltage at the Offshore
Grid Entry Point is outside the limits specified in CC.6.1.4) without exceeding the
transient rating limits of the Offshore Power Park Module and any constituent
Power Park Unit or reactive compensation equipment. For Plant and Apparatus
installed on or after 1 December 2017, switched reactive compensation equipment
(such as mechanically switched capacitors and reactors) shall be controlled such
that it is not switched in or out of service during the fault but may act to assist in
post fault voltage recovery; and,
(iii) within 1 second of the restoration of the voltage at the LV Side of the Offshore
Platform (to the minimum levels specified in CC.6.1.4) restore Active Power to at
least 90% of the Offshore Power Park Module's immediate pre-disturbed value,
unless there has been a reduction in the Intermittent Power Source in the time
range in Figure 7b that restricts the Active Power output below this level. Once the
Active Power output has been restored to the required level, Active Power
oscillations shall be acceptable provided that:
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CC.6.3.15.3
-
the total Active Energy delivered during the period of the oscillations is at
least that which would have been delivered if the Active Power was constant
-
the oscillations are adequately damped
Other Requirements
(i)
In the case of a Power Park Module (comprising of wind-turbine generator units), the
requirements in CC.6.3.15.1 and CC.6.3.15.2 do not apply when the Power Park
Module is operating at less than 5% of its Rated MW or during very high wind speed
conditions when more than 50% of the wind turbine generator units in a Power Park
Module have been shut down or disconnected under an emergency shutdown
sequence to protect User’s Plant and Apparatus.
(ii)
In addition to meeting the conditions specified in CC.6.1.5(b) and CC.6.1.6, each NonSynchronous Generating Unit, OTSDUW Plant and Apparatus or Power Park
Module with a Completion Date after 1 April 2005 and any constituent Power Park
Unit thereof will be required to withstand, without tripping, the negative phase sequence
loading incurred by clearance of a close-up phase-to-phase fault, by System Back-Up
Protection on the Onshore Transmission System operating at Supergrid Voltage.
(iii) In the case of an Onshore Power Park Module in Scotland with a Completion Date
before 1 January 2004 and a Registered Capacity less than 30MW the requirements in
CC.6.3.15.1 (a) do not apply. In the case of an Onshore Power Park Module in
Scotland with a Completion Date on or after 1 January 2004 and before 1 July 2005
and a Registered Capacity less than 30MW the requirements in CC.6.3.15.1 (a) are
relaxed from the minimum Onshore Transmission System Supergrid Voltage of zero
to a minimum Onshore Transmission System Supergrid Voltage of 15% of nominal.
In the case of an Onshore Power Park Module in Scotland with a Completion Date
before 1 January 2004 and a Registered Capacity of 30MW and above the
requirements in CC.6.3.15.1 (a) are relaxed from the minimum Onshore Transmission
System Supergrid Voltage of zero to a minimum Onshore Transmission System
Supergrid Voltage of 15% of nominal.
(iv) To avoid unwanted island operation, Non-Synchronous Generating Units in Scotland
(and those directly connected to a Scottish Offshore Transmission System), Power
Park Modules in Scotland (and those directly connected to a Scottish Offshore
Transmission System) , or OTSDUW Plant and Apparatus with an Interface Point in
Scotland shall be tripped for the following conditions:
(1) Frequency above 52Hz for more than 2 seconds
(2) Frequency below 47Hz for more than 2 seconds
(3) Voltage as measured at the Onshore Connection Point or Onshore User
System Entry Point or Offshore Grid Entry Point or Interface Point in the case
of OTSDUW Plant and Apparatus is below 80% for more than 2.5 seconds
(4) Voltage as measured at the Onshore Connection Point or Onshore User
System Entry Point or Offshore Grid Entry Point or Interface Point in the case
of OTSDUW Plant and Apparatus is above 120% (115% for 275kV) for more than
1 second.
The times in sections (1) and (2) are maximum trip times. Shorter times may be used to
protect the Non-Synchronous Generating Units, or OTSDUW Plant and Apparatus
or Power Park Modules.
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Additional Damping Control Facilities for DC Converters
CC.6.3.16
(a) DC Converter owners, or Generators in respect of OTSDUW DC Converters or
Network Operators in the case of an Embedded DC Converter Station not subject to
a Bilateral Agreement must ensure that any of their Onshore DC Converters or
OTSDUW DC Converters will not cause a sub-synchronous resonance problem on the
Total System. Each DC Converter or OTSDUW DC Converter is required to be
provided with sub-synchronous resonance damping control facilities.
(b) Where specified in the Bilateral Agreement, each DC Converter or OTSDUW DC
Converter is required to be provided with power oscillation damping or any other
identified additional control facilities.
System to Generator Operational Intertripping Scheme
CC.6.3.17
NGET may require that a System to Generator Operational Intertripping Scheme be
installed as part of a condition of the connection of the Generator. Scheme specific details
shall be included in the relevant Bilateral Agreement and shall, in respect of Bilateral
th
Agreements entered into on or after 16 March 2009 include the following information:
(1) the relevant category(ies) of the scheme (referred to as Category 1 Intertripping
Scheme, Category 2 Intertripping Scheme, Category 3 Intertripping Scheme and
Category 4 Intertripping Scheme);
(2) the Generating Unit(s) or CCGT Module(s) or Power Park Module(s) to be either
permanently armed or that can be instructed to be armed in accordance with BC2.8;
(3) the time within which the Generating Unit(s) or CCGT Module(s) or Power Park
Module(s) circuit breaker(s) are to be automatically tripped;
(4) the location to which the trip signal will be provided by NGET. Such location will be
provided by NGET prior to the commissioning of the Generating Unit(s) or CCGT
Module(s) or Power Park Module(s).
Where applicable, the Bilateral Agreement shall include the conditions on the National
Electricity Transmission System during which NGET may instruct the System to
Generator Operational Intertripping Scheme to be armed and the conditions that would
initiate a trip signal.
CC.6.3.18
The time within which the Generating Unit(s) or CCGT Module or Power Park Module
circuit breaker(s) need to be automatically tripped is determined by the specific conditions
local to the Generator. This ‘time to trip’ (defined as time from provision of the trip signal by
NGET to the specified location, to circuit breaker main contact opening) can typically range
from 100ms to 10sec. A longer time to trip may allow the initiation of an automatic reduction
in the Generating Unit(s) or CCGT Module(s) or Power Park Module(s) output prior to the
automatic tripping of the Generating Unit(s) or CCGT Module(s) or Power Park Module(s)
circuit breaker. Where applicable NGET may provide separate trip signals to allow for either
a longer or shorter ‘time to trip’ to be initiated.
CC.6.4
General Network Operator And Non-Embedded Customer Requirements
CC.6.4.1
This part of the Grid Code describes the technical and design criteria and performance
requirements for Network Operators and Non-Embedded Customers.
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Neutral Earthing
CC.6.4.2
At nominal System voltages of 132kV and above the higher voltage windings of three phase
transformers and transformer banks connected to the National Electricity Transmission
System must be star connected with the star point suitable for connection to earth. The
earthing and lower voltage winding arrangement shall be such as to ensure that the Earth
Fault Factor requirement of paragraph CC.6.2.1.1 (b) will be met on the National
Electricity Transmission System at nominal System voltages of 132kV and above.
Frequency Sensitive Relays
CC.6.4.3
As explained under OC6, each Network Operator, will make arrangements that will facilitate
automatic low Frequency Disconnection of Demand (based on Annual ACS Conditions).
CC.A.5.5. of Appendix 5 includes specifications of the local percentage Demand that shall
be disconnected at specific frequencies. The manner in which Demand subject to low
Frequency disconnection will be split into discrete MW blocks is specified in OC6.6.
Technical requirements relating to Low Frequency Relays are also listed in Appendix 5.
Operational Metering
CC.6.4.4
Where NGET can reasonably demonstrate that an Embedded Medium Power Station or
Embedded DC Converter Station has a significant effect on the National Electricity
Transmission System, it may require the Network Operator within whose System the
Embedded Medium Power Station or Embedded DC Converter Station is situated to
ensure that the operational metering equipment described in CC.6.5.6 is installed such that
NGET can receive the data referred to in CC.6.5.6. In the case of an Embedded Medium
Power Station subject to, or proposed to be subject to a Bilateral Agreement NGET shall
notify such Network Operator of the details of such installation in writing within 3 months of
being notified of the application to connect under CUSC and in the case of an Embedded
Medium Power Station not subject to, or not proposed to be subject to a Bilateral
Agreement in writing as a Site Specific Requirement in accordance with the timescales in
CUSC 6.5.5. In either case the Network Operator shall ensure that the data referred to in
CC.6.5.6 is provided to NGET.
CC.6.5
Communications Plant
CC.6.5.1
In order to ensure control of the National Electricity Transmission System,
telecommunications between Users and NGET must (including in respect of any OTSDUW
Plant and Apparatus at the OTSUA Transfer Time), if required by NGET, be established in
accordance with the requirements set down below.
CC.6.5.2
Control Telephony and System Telephony
CC.6.5.2.1
Control Telephony is the principle method by which a User's Responsible
Engineer/Operator and NGET Control Engineers speak to one another for the purposes of
control of the Total System in both normal and emergency operating conditions. Control
Telephony provides secure point to point telephony for routine Control Calls, priority
Control Calls and emergency Control Calls.
CC.6.5.2.2
System Telephony is an alternate method by which a User's Responsible
Engineer/Operator and NGET Control Engineers speak to one another for the purposes of
control of the Total System in both normal operating conditions and where practicable,
emergency operating conditions. System Telephony uses the Public Switched Telephony
Network to provide telephony for Control Calls, inclusive of emergency Control Calls.
CC.6.5.2.3
Calls made and received over Control Telephony and System Telephony may be
recorded and subsequently replayed for commercial and operational reasons.
CC.6.5.3
Supervisory Tones
CC.6.5.3.1
Control Telephony supervisory tones indicate to the calling and receiving parties dial,
engaged, ringing, secondary engaged (signifying that priority may be exercised) and priority
disconnect tones.
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CC.6.5.3.2
System Telephony supervisory tones indicate to the calling and receiving parties dial,
engaged and ringing tones.
CC.6.5.4
Obligations in respect of Control Telephony and System Telephony
CC.6.5.4.1
Where NGET requires Control Telephony, Users are required to use the Control
Telephony with NGET in respect of all Connection Points with the National Electricity
Transmission System and in respect of all Embedded Large Power Stations and
Embedded DC Converter Stations. NGET will install Control Telephony at the User’s
Control Point where the User’s telephony equipment is not capable of providing the
required facilities or is otherwise incompatible with the Transmission Control Telephony.
Details of and relating to the Control Telephony required are contained in the Bilateral
Agreement.
CC.6.5.4.2
Where in NGET’s sole opinion the installation of Control Telephony is not practicable at a
User’s Control Point(s), NGET shall specify in the Bilateral Agreement whether System
Telephony is required. Where System Telephony is required by NGET, the User shall
ensure that System Telephony is installed.
CC.6.5.4.3
Where System Telephony is installed, Users are required to use the System Telephony
with NGET in respect of those Control Point(s) for which it has been installed. Details of
and relating to the System Telephony required are contained in the Bilateral Agreement.
CC.6.5.4.4
Where Control Telephony or System Telephony is installed, routine testing of such
facilities may be required by NGET (not normally more than once in any calendar month).
The User and NGET shall use reasonable endeavours to agree a test programme and
where NGET requests the assistance of the User in performing the agreed test programme
the User shall provide such assistance.
CC.6.5.4.5
Control Telephony and System Telephony shall only be used for the purposes of
operational voice communication between NGET and the relevant User.
CC.6.5.4.6
Control Telephony contains emergency calling functionality to be used for urgent
operational communication only. Such functionality enables NGET and Users to utilise a
priority call in the event of an emergency. NGET and Users shall only use such priority call
functionality for urgent operational communications.
CC.6.5.5
Technical Requirements for Control Telephony and System Telephony
CC.6.5.5.1
Detailed information on the technical interfaces and support requirements for Control
Telephony applicable in NGET’s Transmission Area is provided in the Control Telephony
Electrical Standard identified in the Annex to the General Conditions. Where additional
information, or information in relation to Control Telephony applicable in Scotland, is
requested by Users, this will be provided, where possible, by NGET.
CC.6.5.5.2
System Telephony shall consist of a dedicated Public Switched Telephone Network
telephone line that shall be installed and configured by the relevant User. NGET shall
provide a dedicated free phone number (UK only), for the purposes of receiving incoming
calls to NGET, which Users shall utilise for System Telephony. System Telephony shall
only be utilised by the NGET Control Engineer and the User’s Responsible
Engineer/Operator for the purposes of operational communications.
Operational Metering
CC.6.5.6
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(a) NGET shall provide system control and data acquisition (SCADA) outstation interface
equipment. The User shall provide such voltage, current, Frequency, Active Power
and Reactive Power measurement outputs and plant status indications and alarms to
the Transmission SCADA outstation interface equipment as required by NGET in
accordance with the terms of the Bilateral Agreement. In the case of OTSDUW, the
User shall provide such SCADA outstation interface equipment and voltage, current,
Frequency, Active Power and Reactive Power measurement outputs and plant status
indications and alarms to the SCADA outstation interface equipment as required by
NGET in accordance with the terms of the Bilateral Agreement.
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(b) For the avoidance of doubt, for Active Power and Reactive Power measurements,
circuit breaker and disconnector status indications from:
(i)
CCGT Modules at Large Power Stations, the outputs and status indications must
each be provided to NGET on an individual CCGT Unit basis. In addition, where
identified in the Bilateral Agreement, Active Power and Reactive Power
measurements from Unit Transformers and/or Station Transformers must be
provided.
(ii)
DC Converters at DC Converter Stations and OTSDUW DC Converters, the
outputs and status indications must each be provided to NGET on an individual DC
Converter basis. In addition, where identified in the Bilateral Agreement, Active
Power and Reactive Power measurements from converter and/or station
transformers must be provided.
(iii) Power Park Modules at Embedded Large Power Stations and at directly
connected Power Stations, the outputs and status indications must each be
provided to NGET on an individual Power Park Module basis. In addition, where
identified in the Bilateral Agreement, Active Power and Reactive Power
measurements from station transformers must be provided.
(iv) In respect of OTSDUW Plant and Apparatus, the outputs and status indications
must be provided to NGET for each piece of electrical equipment. In addition,
where identified in the Bilateral Agreement, Active Power and Reactive Power
measurements at the Interface Point must be provided.
(c) For the avoidance of doubt, the requirements of CC.6.5.6(a) in the case of a Cascade
Hydro Scheme will be provided for each Generating Unit forming part of that Cascade
Hydro Scheme. In the case of Embedded Generating Units forming part of a
Cascade Hydro Scheme the data may be provided by means other than a NGET
SCADA outstation located at the Power Station, such as, with the agreement of the
Network Operator in whose system such Embedded Generating Unit is located, from
the Network Operator’s SCADA system to NGET. Details of such arrangements will
be contained in the relevant Bilateral Agreements between NGET and the Generator
and the Network Operator.
(d) In the case of a Power Park Module, additional energy input signals (e.g. wind speed,
and wind direction) may be specified in the Bilateral Agreement. For Power Park
Modules with a Completion Date on or after 1st April 2016 a Power Available signal
will also be specified in the Bilateral Agreement. The signals would be used to
establish the potential level of energy input from the Intermittent Power Source for
monitoring pursuant to CC.6.6.1 and Ancillary Services and will, in the case of a wind
farm, be used to provide NGET with advanced warning of excess wind speed shutdown
and to determine the level of Headroom available from Power Park Modules for the
purposes of calculating response and reserve. For the avoidance of doubt, the Power
Available signal would be automatically provided to NGET and represent the sum of
the potential output of all available and operational Power Park Units within the Power
Park Module. The refresh rate of the Power Available signal shall be specified in the
Bilateral Agreement.
Instructor Facilities
CC.6.5.7
The User shall accommodate Instructor Facilities provided by NGET for the receipt of
operational messages relating to System conditions.
Electronic Data Communication Facilities
CC.6.5.8
(a) All BM Participants must ensure that appropriate electronic data communication
facilities are in place to permit the submission of data, as required by the Grid Code, to
NGET.
(b) In addition,
(1) any User that wishes to participate in the Balancing Mechanism;
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or
(2) any BM Participant in respect of its BM Units at a Power Station where the
Construction Agreement and/or a Bilateral Agreement has a Completion Date
on or after 1 January 2013 and the BM Participant is required to provide all Part 1
System Ancillary Services in accordance with CC.8.1 (unless NGET has
otherwise agreed)
must ensure that appropriate automatic logging devices are installed at the Control
Points of its BM Units to submit data to and to receive instructions from NGET, as
required by the Grid Code. For the avoidance of doubt, in the case of an
Interconnector User the Control Point will be at the Control Centre of the
appropriate Externally Interconnected System Operator.
(c) Detailed specifications of these required electronic facilities will be provided by NGET
on request and they are listed as Electrical Standards in the Annex to the General
Conditions.
Facsimile Machines
CC.6.5.9
Each User and NGET shall provide a facsimile machine or machines:
(a) in the case of Generators, at the Control Point of each Power Station and at its
Trading Point;
(b) in the case of NGET and Network Operators, at the Control Centre(s); and
(c) in the case of Non-Embedded Customers and DC Converter Station owners at the
Control Point.
Each User shall notify, prior to connection to the System of the User's Plant and
Apparatus, NGET of its or their telephone number or numbers, and will notify NGET of any
changes. Prior to connection to the System of the User's Plant and Apparatus NGET shall
notify each User of the telephone number or numbers of its facsimile machine or machines
and will notify any changes.
CC.6.5.10
Busbar Voltage
NGET shall, subject as provided below, provide each Generator or DC Converter Station
owner at each Grid Entry Point where one of its Power Stations or DC Converter
Stations is connected with appropriate voltage signals to enable the Generator or DC
Converter Station owner to obtain the necessary information to permit its Gensets or DC
Converters to be Synchronised to the National Electricity Transmission System. The
term "voltage signal" shall mean in this context, a point of connection on (or wire or wires
from) a relevant part of Transmission Plant and/or Apparatus at the Grid Entry Point, to
which the Generator or DC Converter Station owner, with NGET's agreement (not to be
unreasonably withheld) in relation to the Plant and/or Apparatus to be attached, will be able
to attach its Plant and/or Apparatus (normally a wire or wires) in order to obtain
measurement outputs in relation to the busbar.
CC.6.5.11
Bilingual Message Facilities
(a) A Bilingual Message Facility is the method by which the User’s Responsible
Engineer/Operator, the Externally Interconnected System Operator and NGET
Control Engineers communicate clear and unambiguous information in two languages
for the purposes of control of the Total System in both normal and emergency
operating conditions.
(b) A Bilingual Message Facility, where required, will provide up to two hundred pre-defined
messages with up to five hundred and sixty characters each. A maximum of one minute
is allowed for the transmission to, and display of, the selected message at any
destination. The standard messages must be capable of being displayed at any
combination of locations and can originate from any of these locations. Messages
displayed in the UK will be displayed in the English language.
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(c) Detailed information on a Bilingual Message Facility and suitable equipment required for
individual User applications will be provided by NGET upon request.
CC.6.6
System Monitoring
CC.6.6.1
Monitoring equipment is provided on the National Electricity Transmission System to
enable NGET to monitor its power system dynamic performance conditions. Where this
monitoring equipment requires voltage and current signals on the Generating Unit (other
than Power Park Unit), DC Converter or Power Park Module circuit from the User or from
OTSDUW Plant and Apparatus, NGET will inform the User and they will be provided by the
User with both the timing of the installation of the equipment for receiving such signals and
its exact position being agreed (the User's agreement not to be unreasonably withheld) and
the costs being dealt with, pursuant to the terms of the Bilateral Agreement.
CC.6.6.2
For all on site monitoring by NGET of witnessed tests pursuant to the CP or OC5 the User
shall provide suitable test signals as outlined in OC5.A.1.
CC.6.6.2.1
The signals which shall be provided by the User to NGET for onsite monitoring shall be of
the following resolution, unless otherwise agreed by NGET:
(i)
1 Hz for reactive range tests
(ii)
10 Hz for frequency control tests
(iii) 100 Hz for voltage control tests
CC.6.6.2.2
CC.6.6.2.3
The User will provide all relevant signals for this purpose in the form of d.c. voltages within
the range -10V to +10V. In exceptional circumstances some signals may be accepted as d.c.
voltages within the range -60V to +60V with prior agreement between the User and NGET.
All signals shall:
(i)
in the case of an Onshore Power Park Module, DC Convertor Station or
Synchronous Generating Unit, be suitably terminated in a single accessible location
at the Generator or DC Converter Station owner’s site.
(ii)
in the case of an Offshore Power Park Module and OTSDUW Plant and Apparatus,
be transmitted onshore without attenuation, delay or filtering which would result in the
inability to fully demonstrate the objectives of the test, or identify any potential safety or
plant instability issues, and be suitably terminated in a single robust location normally
located at or near the onshore Interface Point of the Offshore Transmission System
to which it is connected.
All signals shall be suitably scaled across the range. The following scaling would (unless
NGET notify the User otherwise) be acceptable to NGET:
(a) 0MW to Registered Capacity or Interface Point Capacity 0-8V dc
(b) Maximum leading Reactive Power to maximum lagging Reactive Power -8 to 8V dc
(c) 48 – 52Hz as -8 to 8V dc
(d) Nominal terminal or connection point voltage -10% to +10% as -8 to 8V dc
CC.6.6.2.4
The User shall provide to NGET a 230V power supply adjacent to the signal terminal
location.
CC.7
SITE RELATED CONDITIONS
CC.7.1
Not used.
CC.7.2
Responsibilities For Safety
CC.7.2.1
In England and Wales, any User entering and working on its Plant and/or Apparatus
(including, until the OTSUA Transfer Time, any OTSUA) on a Transmission Site will work
to the Safety Rules of NGET.
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In Scotland or Offshore, any User entering and working on its Plant and/or Apparatus
(including, until the OTSUA Transfer Time, any OTSUA) on a Transmission Site will work
to the Safety Rules of the Relevant Transmission Licensee, as advised by NGET.
CC.7.2.2
NGET entering and working on Transmission Plant and/or Apparatus on a User Site will
work to the User's Safety Rules. For User Sites in Scotland or Offshore, NGET shall
procure that the Relevant Transmission Licensee entering and working on Transmission
Plant and/or Apparatus on a User Site will work to the User’s Safety Rules.
CC.7.2.3
A User may, with a minimum of six weeks notice, apply to NGET for permission to work
according to that Users own Safety Rules when working on its Plant and/or Apparatus on
a Transmission Site rather than those set out in CC.7.2.1. If NGET is of the opinion that
the User's Safety Rules provide for a level of safety commensurate with those set out in
CC.7.2.1, NGET will notify the User, in writing, that, with effect from the date requested by
the User, the User may use its own Safety Rules when working on its Plant and/or
Apparatus on the Transmission Site. For a Transmission Site in Scotland or Offshore,
in forming its opinion, NGET will seek the opinion of the Relevant Transmission Licensee.
Until receipt of such written approval from NGET, the User will continue to use the Safety
Rules as set out in CC.7.2.1.
CC.7.2.4
In the case of a User Site in England and Wales, NGET may, with a minimum of six weeks
notice, apply to a User for permission to work according to NGET’s Safety Rules when
working on Transmission Plant and/or Apparatus on that User Site, rather than the User’s
Safety Rules. If the User is of the opinion that NGET’s Safety Rules provide for a level of
safety commensurate with that of that User’s Safety Rules, it will notify NGET, in writing,
that, with the effect from the date requested by NGET, NGET may use its own Safety Rules
when working on its Transmission Plant and/or Apparatus on that User Site. Until receipt
of such written approval from the User, NGET shall continue to use the User’s Safety
Rules.
In the case of a User Site in Scotland or Offshore, NGET may, with a minimum of six weeks
notice, apply to a User for permission for the Relevant Transmission Licensee to work
according to the Relevant Transmission Licensee’s Safety Rules when working on
Transmission Plant and/or Apparatus on that User Site, rather than the User’s Safety
Rules. If the User is of the opinion that the Relevant Transmission Licensee’s Safety
Rules, provide for a level of safety commensurate with that of that User’s Safety Rules, it
will notify NGET, in writing, that, with effect from the date requested by NGET, that the
Relevant Transmission Licensee may use its own Safety Rules when working on its
Transmission Plant and/or Apparatus on that User’s Site. Until receipt of such written
approval from the User, NGET shall procure that the Relevant Transmission Licensee
shall continue to use the User’s Safety Rules.
CC.7.2.5
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For a Transmission Site in England and Wales, if NGET gives its approval for the User’s
Safety Rules to apply to the User when working on its Plant and/or Apparatus, that does
not imply that the User’s Safety Rules will apply to entering the Transmission Site and
access to the User’s Plant and/or Apparatus on that Transmission Site. Bearing in mind
NGET’s responsibility for the whole Transmission Site, entry and access will always be in
accordance with NGET’s site access procedures. For a User Site in England and Wales, if
the User gives its approval for NGET’s Safety Rules to apply to NGET when working on its
Plant and Apparatus, that does not imply that NGET’s Safety Rules will apply to entering
the User Site, and access to the Transmission Plant and Apparatus on that User Site.
Bearing in mind the User’s responsibility for the whole User Site, entry and access will
always be in accordance with the User’s site access procedures.
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For a Transmission Site in Scotland or Offshore, if NGET gives its approval for the User’s
Safety Rules to apply to the User when working on its Plant and/or Apparatus, that does
not imply that the User’s Safety Rules will apply to entering the Transmission Site and
access to the User’s Plant and/or Apparatus on that Transmission Site. Bearing in mind
the Relevant Transmission Licensee’s responsibility for the whole Transmission Site,
entry and access will always be in accordance with the Relevant Transmission Licensee’s
site access procedures. For a User Site in Scotland or Offshore, if the User gives its
approval for Relevant Transmission Licensee Safety Rules to apply to the Relevant
Transmission Licensee when working on its Plant and Apparatus, that does not imply that
the Relevant Transmission Licensee’s Safety Rules will apply to entering the User Site,
and access to the Transmission Plant and Apparatus on that User Site. Bearing in mind
the User’s responsibility for the whole User Site, entry and access will always be in
accordance with the User’s site access procedures.
CC.7.2.6
For User Sites in England and Wales, Users shall notify NGET of any Safety Rules that
apply to NGET’s staff working on User Sites. For Transmission Sites in England and
Wales, NGET shall notify Users of any Safety Rules that apply to the User’s staff working
on the Transmission Site.
For User Sites in Scotland or Offshore, Users shall notify NGET of any Safety Rules that
apply to the Relevant Transmission Licensee’s staff working on User Sites. For
Transmission Sites in Scotland or Offshore NGET shall procure that the Relevant
Transmission Licensee shall notify Users of any Safety Rules that apply to the User’s
staff working on the Transmission Site.
CC.7.2.7
Each Site Responsibility Schedule must have recorded on it the Safety Rules which apply
to each item of Plant and/or Apparatus.
CC.7.2.8
In the case of OTSUA a User Site or Transmission Site shall, for the purposes of this
CC.7.2, include a site at which there is an Interface Point until the OTSUA Transfer Time
when it becomes part of the National Electricity Transmission System.
CC.7.3
Site Responsibility Schedules
CC.7.3.1
In order to inform site operational staff and NGET Control Engineers of agreed
responsibilities for Plant and/or Apparatus at the operational interface, a Site
Responsibility Schedule shall be produced for Connection Sites (and in the case of
OTSUA, until the OTSUA Transfer Time, Interface Sites) in England and Wales for NGET
and Users with whom they interface, and for Connection Sites (and in the case of OTSUA,
until the OTSUA Transfer Time, Interface Sites) in Scotland or Offshore for NGET, the
Relevant Transmission Licensee and Users with whom they interface.
CC.7.3.2
The format, principles and basic procedure to be used in the preparation of Site
Responsibility Schedules are set down in Appendix 1.
CC.7.4
Operation And Gas Zone Diagrams
Operation Diagrams
CC.7.4.1
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An Operation Diagram shall be prepared for each Connection Site at which a Connection
Point exists (and in the case of OTSDUW Plant and Apparatus, by User’s for each
Interface Point) using, where appropriate, the graphical symbols shown in Part 1A of
Appendix 2. Users should also note that the provisions of OC11 apply in certain
circumstances.
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CC.7.4.2
The Operation Diagram shall include all HV Apparatus and the connections to all external
circuits and incorporate numbering, nomenclature and labelling, as set out in OC11. At those
Connection Sites (or in the case of OTSDUW Plant and Apparatus, Interface Points)
where gas-insulated metal enclosed switchgear and/or other gas-insulated HV Apparatus is
installed, those items must be depicted within an area delineated by a chain dotted line
which intersects gas-zone boundaries. The nomenclature used shall conform with that used
on the relevant Connection Site and circuit (and in the case of OTSDUW Plant and
Apparatus, Interface Point and circuit). The Operation 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 HV Apparatus and related Plant.
CC.7.4.3
A non-exhaustive guide to the types of HV Apparatus to be shown in the Operation
Diagram is shown in Part 2 of Appendix 2, together with certain basic principles to be
followed unless equivalent principles are approved by NGET.
Gas Zone Diagrams
CC.7.4.4
A Gas Zone Diagram shall be prepared for each Connection Site at which a Connection
Point (and in the case of OTSDUW Plant and Apparatus, by User’s for an Interface Point)
exists where gas-insulated switchgear and/or other gas-insulated HV Apparatus is utilised.
They shall use, where appropriate, the graphical symbols shown in Part 1B of Appendix 2.
CC.7.4.5
The nomenclature used shall conform with that used in the relevant Connection Site and
circuit (and in the case of OTSDUW Plant and Apparatus, relevant Interface Point and
circuit).
CC.7.4.6
The basic principles set out in Part 2 of Appendix 2 shall be followed in the preparation of
Gas Zone Diagrams unless equivalent principles are approved by NGET.
Preparation of Operation and Gas Zone Diagrams for Users' Sites and Transmission
Interface Sites
CC.7.4.7
In the case of a User Site, the User shall prepare and submit to NGET, an Operation
Diagram for all HV Apparatus on the User side of the Connection Point (and in the case
of OTSDUW Plant and Apparatus, on what will be the Offshore Transmission side of the
Connection Point and the Interface Point) and NGET shall provide the User with an
Operation Diagram for all HV Apparatus on the Transmission side of the Connection
Point (and in the case of OTSDUW Plant and Apparatus on what will be the Onshore
Transmission side of the Interface Point, in accordance with the timing requirements of the
Bilateral Agreement and/or Construction Agreement prior to the Completion Date under
the Bilateral Agreement and/or Construction Agreement.
CC.7.4.8
The User will then prepare, produce and distribute, using the information submitted on the
User's Operation Diagram and NGET Operation Diagram, a composite Operation
Diagram for the complete Connection Site (and in the case of OTSDUW Plant and
Apparatus, Interface Point), also in accordance with the timing requirements of the
Bilateral Agreement and/or Construction Agreement .
CC.7.4.9
The provisions of CC.7.4.7 and CC.7.4.8 shall apply in relation to Gas Zone Diagrams
where gas-insulated switchgear and/or other gas-insulated HV Apparatus is utilised.
Preparation of Operation and Gas Zone Diagrams for Transmission Sites
CC.7.4.10
In the case of an Transmission Site, the User shall prepare and submit to NGET an
Operation Diagram for all HV Apparatus on the User side of the Connection Point, in
accordance with the timing requirements of the Bilateral Agreement and/or Construction
Agreement.
CC.7.4.11
NGET will then prepare, produce and distribute, using the information submitted on the
User's Operation Diagram, a composite Operation Diagram for the complete Connection
Site, also in accordance with the timing requirements of the Bilateral Agreement and/or
Construction Agreement .
CC.7.4.12
The provisions of CC.7.4.10 and CC.7.4.11 shall apply in relation to Gas Zone Diagrams
where gas-insulated switchgear and/or other gas-insulated HV Apparatus is utilised.
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CC.7.4.13
Changes to Operation and Gas Zone Diagrams
CC.7.4.13.1
When NGET has decided that it wishes to install new HV Apparatus or it wishes to change
the existing numbering or nomenclature of Transmission HV Apparatus at a Transmission
Site, NGET will (unless it gives rise to a Modification under the CUSC, in which case the
provisions of the CUSC as to the timing apply) one month prior to the installation or change,
send to each such User a revised Operation Diagram of that Transmission Site,
incorporating the new Transmission HV Apparatus to be installed and its numbering and
nomenclature or the changes, as the case may be. OC11 is also relevant to certain
Apparatus.
CC.7.4.13.2
When a User has decided that it wishes to install new HV Apparatus, or it wishes to change
the existing numbering or nomenclature of its HV Apparatus at its User Site, the User will
(unless it gives rise to a Modification under the CUSC, in which case the provisions of the
CUSC as to the timing apply) one month prior to the installation or change, send to NGET a
revised Operation Diagram of that User Site incorporating the new User HV Apparatus to
be installed and its numbering and nomenclature or the changes as the case may be. OC11
is also relevant to certain Apparatus.
CC.7.4.13.3
The provisions of CC.7.4.13.1 and CC.7.4.13.2 shall apply in relation to Gas Zone
Diagrams where gas-insulated switchgear and/or other gas-insulated HV Apparatus is
installed.
Validity
CC.7.4.14
(a) The composite Operation Diagram prepared by NGET or the User, as the case may
be, will be the definitive Operation Diagram for all operational and planning activities
associated with the Connection Site. If a dispute arises as to the accuracy of the
composite Operation Diagram, a meeting shall be held at the Connection Site, as
soon as reasonably practicable, between NGET and the User, to endeavour to resolve
the matters in dispute.
(b) The composite Operation Diagram prepared by NGET or the User, as the case may
be, will be the definitive Operation Diagram for all operational and planning activities
associated with the Interface Point until the OTSUA Transfer Time. If a dispute arises
as to the accuracy of the composite Operation Diagram prior to the OTSUA Transfer
Time, a meeting shall be held at the Interface Point, as soon as reasonably
practicable, between NGET and the User, to endeavour to resolve the matters in
dispute.
(c) An equivalent rule shall apply for Gas Zone Diagrams where they exist for a
Connection Site.
CC.7.4.15
In the case of OTSUA, a User Site and Transmission Site shall, for the purposes of this
CC.7.4, include a site at which there is an Interface Point until the OTSUA Transfer Time
when it becomes part of the National Electricity Transmission System and references to
HV Apparatus in this CC.7.4 shall include references to HV OTSUA.
CC.7.5
Site Common Drawings
CC.7.5.1
Site Common Drawings will be prepared for each Connection Site (and in the case of
OTSDUW, each Interface Point) and will include Connection Site (and in the case of
OTSDUW, Interface Point) layout drawings, electrical layout drawings, common
Protection/control drawings and common services drawings.
Preparation of Site Common Drawings for a User Site and Transmission Interface Site
CC.7.5.2
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In the case of a User Site, NGET shall prepare and submit to the User, Site Common
Drawings for the Transmission side of the Connection Point (and in the case of OTSDUW
Plant and Apparatus, on what will be the Onshore Transmission side of the Interface
Point,) and the User shall prepare and submit to NGET, Site Common Drawings for the
User side of the Connection Point (and in the case of OTSDUW, on what will be the
Offshore Transmission side of the Interface Point) in accordance with the timing
requirements of the Bilateral Agreement and/or Construction Agreement.
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CC.7.5.3
The User will then prepare, produce and distribute, using the information submitted on the
Transmission Site Common Drawings, Site Common Drawings for the complete
Connection Site (and in the case of OTSDUW, Interface Point) in accordance with the
timing requirements of the Bilateral Agreement and/or Construction Agreement .
Preparation of Site Common Drawings for a Transmission Site
CC.7.5.4
In the case of a Transmission Site, the User will prepare and submit to NGET Site
Common Drawings for the User side of the Connection Point in accordance with the
timing requirements of the Bilateral Agreement and/or Construction Agreement.
CC.7.5.5
NGET will then prepare, produce and distribute, using the information submitted in the
User's Site Common Drawings, Site Common Drawings for the complete Connection
Site in accordance with the timing requirements of the Bilateral Agreement and/or
Construction Agreement.
CC.7.5.6
When a User becomes aware that it is necessary to change any aspect of the Site
Common Drawings at a Connection Site (and in the case of OTSDUW, Interface Point) it
will:
(a) if it is a User Site, as soon as reasonably practicable, prepare, produce and distribute
revised Site Common Drawings for the complete Connection Site (and in the case of
OTSDUW, Interface Point); and
(b) if it is a Transmission Site, as soon as reasonably practicable, prepare and submit to
NGET revised Site Common Drawings for the User side of the Connection Point
(and in the case of OTSDUW, Interface Point) and NGET will then, as soon as
reasonably practicable, prepare, produce and distribute, using the information submitted
in the User's Site Common Drawings, revised Site Common Drawings for the
complete Connection Site (and in the case of OTSDUW, Interface Point).
In either case, if in the User's reasonable opinion the change can be dealt with by it notifying
NGET in writing of the change and for each party to amend its copy of the Site Common
Drawings (or where there is only one set, for the party holding that set to amend it), then it
shall so notify and each party shall so amend. If the change gives rise to a Modification
under the CUSC, the provisions of the CUSC as to timing will apply.
CC.7.5.7
When NGET becomes aware that it is necessary to change any aspect of the Site Common
Drawings at a Connection Site(and in the case of OTSDUW, Interface Point) it will:
(a) if it is a Transmission Site, as soon as reasonably practicable, prepare, produce and
distribute revised Site Common Drawings for the complete Connection Site (and in
the case of OTSDUW, Interface Point); and
(b) if it is a User Site, as soon as reasonably practicable, prepare and submit to the User
revised Site Common Drawings for the Transmission side of the Connection Point
(in the case of OTSDUW, Interface Point) and the User will then, as soon as
reasonably practicable, prepare, produce and distribute, using the information submitted
in the Transmission Site Common Drawings, revised Site Common Drawings for
the complete Connection Site (and in the case of OTSDUW, Interface Point).
In either case, if in NGET's reasonable opinion the change can be dealt with by it notifying
the User in writing of the change and for each party to amend its copy of the Site Common
Drawings (or where there is only one set, for the party holding that set to amend it), then it
shall so notify and each party shall so amend. If the change gives rise to a Modification
under the CUSC, the provisions of the CUSC as to timing will apply.
Validity
CC.7.5.8
Issue 5 Revision 21
(a) The Site Common Drawings for the complete Connection Site prepared by the User
or NGET, as the case may be, will be the definitive Site Common Drawings for all
operational and planning activities associated with the Connection Site. If a dispute
arises as to the accuracy of the Site Common Drawings, a meeting shall be held at the
Site, as soon as reasonably practicable, between NGET and the User, to endeavour to
resolve the matters in dispute.
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(b) The Site Common Drawing prepared by NGET or the User, as the case may be, will
be the definitive Site Common Drawing for all operational and planning activities
associated with the Interface Point until the OTSUA Transfer Time. If a dispute arises
as to the accuracy of the composite Operation Diagram prior to the OTSUA Transfer
Time, a meeting shall be held at the Interface Point, as soon as reasonably
practicable, between NGET and the User, to endeavour to resolve the matters in
dispute.
CC.7.5.9
In the case of OTSUA, a User Site and Transmission Site shall, for the purposes of this
CC.7.5, include a site at which there is an Interface Point until the OTSUA Transfer Time
when it becomes part of the National Electricity Transmission System.
CC.7.6
Access
CC.7.6.1
The provisions relating to access to Transmission Sites by Users, and to Users' Sites by
Transmission Licensees, are set out in each Interface Agreement (or in the case of
Interfaces Sites prior to the OTSUA Transfer Time agreements in similar form) with, for
Transmission Sites in England and Wales, NGET and each User, and for Transmission
Sites in Scotland and Offshore, the Relevant Transmission Licensee and each User.
CC.7.6.2
In addition to those provisions, where a Transmission Site in England and Wales contains
exposed HV conductors, unaccompanied access will only be granted to individuals holding
an Authority for Access issued by NGET and where a Transmission Site in Scotland or
Offshore contains exposed HV conductors, unaccompanied access will only be granted to
individuals holding an Authority for Access issued by the Relevant Transmission
Licensee.
CC.7.6.3
The procedure for applying for an Authority for Access is contained in the Interface
Agreement.
CC.7.7
Maintenance Standards
CC.7.7.1
It is the User's responsibility to ensure that all its Plant and Apparatus (including, until the
OTSUA Transfer Time, any OTSUA) on a Transmission Site is tested and 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 Transmission Plant, Apparatus or personnel on the
Transmission Site. NGET will have the right to inspect the test results and maintenance
records relating to such Plant and Apparatus at any time
CC.7.7.2
For User Sites in England and Wales, NGET has a responsibility to ensure that all
Transmission Plant and Apparatus on a User Site is tested and 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's Plant, Apparatus or personnel on the User Site.
For User Sites in Scotland and Offshore, NGET shall procure that the Relevant
Transmission Licensee has a responsibility to ensure that all Transmission Plant and
Apparatus on a User Site is tested and 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’s Plant,
Apparatus or personnel on the User Site.
The User will have the right to inspect the test results and maintenance records relating to
such Plant and Apparatus on its User Site at any time.
CC.7.8
Site Operational Procedures
CC.7.8.1
NGET and Users with an interface with NGET, 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 operation of Plant and Apparatus (including, prior
to the OTSUA Transfer Time, any OTSUA) connected to the Total System.
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CC.7.9
Generators and DC Converter Station owners shall provide a Control Point in respect of
each Power Station directly connected to the National Electricity Transmission System
and Embedded Large Power Station or DC Converter Station to receive an act upon
instructions pursuant to OC7 and BC2 at all times that Generating Units or Power Park
Modules at the Power Station are generating or available to generate or DC Converters at
the DC Converter Station are importing or exporting or available to do so. The Control
Point shall be continuously manned except where the Bilateral Agreement in respect of
such Embedded Power Station specifies that compliance with BC2 is not required, where
the Control Point shall be manned between the hours of 0800 and 1800 each day.
CC.8
ANCILLARY SERVICES
CC.8.1
System Ancillary Services
The CC contain requirements for the capability for certain Ancillary Services, which are
needed for System reasons ("System Ancillary Services"). There follows a list of these
System Ancillary Services, together with the paragraph number of the CC (or other part of
the Grid Code) in which the minimum capability is required or referred to. The list is divided
into two categories: Part 1 lists the System Ancillary Services which
(a) Generators in respect of Large Power Stations are obliged to provide (except
Generators in respect of Large Power Stations which have a Registered Capacity of
less than 50MW and comprise Power Park Modules); and,
(b) Generators in respect of Large Power Stations with a Registered Capacity of less
than 50MW and comprise Power Park Modules are obliged to provide in respect of
Reactive Power only; and,
(c) DC Converter Station owners are obliged to have the capability to supply; and
(d) Generators in respect of Medium Power Stations (except Embedded Medium Power
Stations) are obliged to provide in respect of Reactive Power only:
and Part 2 lists the System Ancillary Services which Generators will provide only if
agreement to provide them is reached with NGET:
Part 1
(a) Reactive Power supplied (in accordance with CC.6.3.2) otherwise than by means of
synchronous or static compensators (except in the case of a Power Park Module
where synchronous or static compensators within the Power Park Module may be
used to provide Reactive Power)
(b) Frequency Control by means of Frequency sensitive generation - CC.6.3.7 and
BC3.5.1
Part 2
(c) Frequency Control by means of Fast Start - CC.6.3.14
(d) Black Start Capability - CC.6.3.5
(e) System to Generator Operational Intertripping
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CC.8.2
Commercial Ancillary Services
Other Ancillary Services are also utilised by NGET in operating the Total System if these
have been agreed to be provided by a User (or other person) under an Ancillary Services
Agreement or under a Bilateral Agreement, with payment being dealt with under an
Ancillary Services Agreement or in the case of Externally Interconnected System
Operators or Interconnector Users, under any other agreement (and in the case of
Externally Interconnected System Operators and Interconnector Users includes
ancillary services equivalent to or similar to System Ancillary Services) ("Commercial
Ancillary Services"). The capability for these Commercial Ancillary Services is set out in
the relevant Ancillary Services Agreement or Bilateral Agreement (as the case may be).
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APPENDIX 1 - SITE RESPONSIBILITY SCHEDULES
FORMAT, PRINCIPLES AND BASIC PROCEDURE TO BE USED IN THE PREPARATION
OF SITE RESPONSIBILITY SCHEDULES
CC.A.1.1
Principles
Types of Schedules
CC.A.1.1.1
At all Complexes (which in the context of this CC shall include, Interface Sites until the
OTSUA Transfer Time) the following Site Responsibility Schedules shall be drawn up
using the relevant proforma attached or with such variations as may be agreed between
NGET and Users, but in the absence of agreement the relevant proforma attached will be
used. In addition, in the case of OTSDUW Plant and Apparatus, and in readiness for the
OTSUA Transfer Time, the User shall provide NGET with the necessary information such
that Site Responsibility Schedules in this form can be prepared by the Relevant
Transmission Licensees for the Transmission Interface Site:
(a) Schedule of HV Apparatus
(b) Schedule of Plant, LV/MV Apparatus, services and supplies;
(c) Schedule of telecommunications and measurements Apparatus.
Other than at Generating Unit, DC Converter, Power Park Module and Power Station
locations, the schedules referred to in (b) and (c) may be combined.
New Connection Sites
CC.A.1.1.2
In the case of a new Connection Site each Site Responsibility Schedule for a
Connection Site shall be prepared by NGET in consultation with relevant Users at least 2
weeks prior to the Completion Date (or, where the OTSUA is to become Operational prior
to the OTSUA Transfer Time, an alternative date) under the Bilateral Agreement and/or
Construction Agreement for that Connection Site (which may form part of a Complex).
In the case of a new Interface Site where the OTSUA is to become Operational prior to the
OTSUA Transfer Time each Site Responsibility Schedule for an Interface Site shall be
prepared by NGET in consultation with relevant Users at least 2 weeks prior to the
Completion Date under the Bilateral Agreement and/or Construction Agreement for that
Interface Site (which may form part of a Complex) (and references to and requirements
placed on “Connection Site” in this CC shall also be read as “Interface Site” where the
context requires and until the OTSUA Transfer Time). Each User shall, in accordance with
the timing requirements of the Bilateral Agreement and/or Construction Agreement ,
provide information to NGET to enable it to prepare the Site Responsibility Schedule.
Sub-division
CC.A.1.1.3
Each Site Responsibility Schedule will be subdivided to take account of any separate
Connection Sites on that Complex.
Scope
CC.A.1.1.4
Each Site Responsibility Schedule shall detail for each item of Plant and Apparatus:
(a) Plant/Apparatus ownership;
(b) Site Manager (Controller) (except in the case of Plant/Apparatus located in SPT’s
Transmission Area);
(c) Safety issues comprising applicable Safety Rules and Control Person or other
responsible person (Safety Co-ordinator), or such other person who is responsible for
safety;
(d) Operations issues comprising applicable Operational Procedures and control
engineer;
(e) Responsibility to undertake statutory inspections, fault investigation and maintenance.
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Each Connection Point shall be precisely shown.
Detail
CC.A.1.1.5
(a) In the case of Site Responsibility Schedules referred to in CC.A.1.1.1(b) and (c), with
the exception of Protection Apparatus and Intertrip Apparatus operation, it will be
sufficient to indicate the responsible User or Transmission Licensee, as the case may
be.
(b) In the case of the Site Responsibility Schedule referred to in CC.A.1.1.1(a) and for
Protection Apparatus and Intertrip Apparatus, the responsible management unit
must be shown in addition to the User or Transmission Licensee, as the case may be.
CC.A.1.1.6
The HV Apparatus Site Responsibility Schedule for each Connection Site must include
1
lines and cables emanating from or traversing the Connection Site.
Issue Details
CC.A.1.1.7
Every page of each Site Responsibility Schedule shall bear the date of issue and the issue
number.
Accuracy Confirmation
CC.A.1.1.8
When a Site Responsibility Schedule is prepared it shall be sent by NGET to the Users
involved for confirmation of its accuracy.
CC.A.1.1.9
The Site Responsibility Schedule shall then be signed on behalf of NGET by its
Responsible Manager (see CC.A.1.1.16) and on behalf of each User involved by its
Responsible Manager (see CC.A.1.1.16), by way of written confirmation of its accuracy.
For Connection Sites in Scotland or Offshore, the Site Responsibility Schedule will also
be signed on behalf of the Relevant Transmission Licensee by its Responsible Manager.
Distribution and Availability
CC.A.1.1.10
Once signed, two copies will be distributed by NGET, not less than two weeks prior to its
implementation date, to each User which is a party on the Site Responsibility Schedule,
accompanied by a note indicating the issue number and the date of implementation.
CC.A.1.1.11
NGET and Users must make the Site Responsibility Schedules readily available to
operational staff at the Complex and at the other relevant control points.
Alterations to Existing Site Responsibility Schedules
CC.A 1.1.12
Without prejudice to the provisions of CC.A.1.1.15 which deals with urgent changes, when a
User identified on a Site Responsibility Schedule becomes aware that an alteration is
necessary, it must inform NGET immediately and in any event 8 weeks prior to any change
taking effect (or as soon as possible after becoming aware of it, if less than 8 weeks remain
when the User becomes aware of the change). This will cover the commissioning of new
Plant and/or Apparatus at the Connection Site, whether requiring a revised Bilateral
Agreement or not, de-commissioning of Plant and/or Apparatus, and other changes which
affect the accuracy of the Site Responsibility Schedule.
CC.A 1.1.13
Where NGET has been informed of a change by a User, or itself proposes a change, it will
prepare a revised Site Responsibility Schedule by not less than six weeks prior to the
change taking effect (subject to it having been informed or knowing of the change eight
weeks prior to that time) and the procedure set out in CC.A.1.1.8 shall be followed with
regard to the revised Site Responsibility Schedule.
CC.A 1.1.14
The revised Site Responsibility Schedule shall then be signed in accordance with the
procedure set out in CC.A.1.1.9 and distributed in accordance with the procedure set out in
CC.A.1.1.10, accompanied by a note indicating where the alteration(s) has/have been made,
the new issue number and the date of implementation.
1
Details of circuits traversing the Connection Site are only needed from the date which is the earlier of the date when the Site
Responsibility Schedule is first updated and 15th October 2004. In Scotland or Offshore, from a date to be agreed between NGET
and the Relevant Transmission Licensee.
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Urgent Changes
CC.A.1.1.15
When a User identified on a Site Responsibility Schedule, or NGET, as the case may be,
becomes aware that an alteration to the Site Responsibility Schedule is necessary
urgently to reflect, for example, an emergency situation which has arisen outside its control,
the User shall notify NGET, or NGET shall notify the User, as the case may be, immediately
and will discuss:
(a) what change is necessary to the Site Responsibility Schedule;
(b) whether the Site Responsibility Schedule is to be modified temporarily or
permanently;
(c) the distribution of the revised Site Responsibility Schedule.
NGET will prepare a revised Site Responsibility Schedule as soon as possible, and in any
event within seven days of it being informed of or knowing the necessary alteration. The
Site Responsibility Schedule will be confirmed by Users and signed on behalf of NGET
and Users (by the persons referred to in CC.A.1.1.9) as soon as possible after it has been
prepared and sent to Users for confirmation.
Responsible Managers
CC.A.1.1.16
Each User shall, prior to the Completion Date under each Bilateral Agreement and/or
Construction Agreement, supply to NGET a list of Managers who have been duly
authorised to sign Site Responsibility Schedules on behalf of the User and NGET shall,
prior to the Completion Date under each Bilateral Agreement and/or Construction
Agreement, supply to that User the name of its Responsible Manager and for Connection
Sites in Scotland or Offshore, the name of the Relevant Transmission Licensee’s
Responsible Manager and each shall supply to the other any changes to such list six
weeks before the change takes effect where the change is anticipated, and as soon as
possible after the change, where the change was not anticipated.
De-commissioning of Connection Sites
CC.A.1.1.17
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Where a Connection Site is to be de-commissioned, whichever of NGET or the User who is
initiating the de-commissioning must contact the other to arrange for the Site Responsibility
Schedule to be amended at the relevant time.
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PROFORMA FOR SITE RESPONSIBILITY SCHEDULE
AREA
COMPLEX:
SCHEDULE:
CONNECTION SITE:
SAFETY
ITEM OF
PLANT/
APPARATUS
PLANT
APPARATUS
OWNER
PAGE:
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SITE
MANAGER
SAFETY
RULES
OPERATIONS
CONTROL OR
OTHER
RESPONSIBLE
PERSON
(SAFETY COORDINATOR
OPERATIONAL
PROCEDURES
ISSUE NO:
CONTROL OR
OTHER
RESPONSIBLE
ENGINEER
PARTY
RESPONSIBLE
FOR
UNDERTAKING
STATUTORY
INSPECTIONS,
FAULT
INVESTIGATION
&
MAINTENANCE
REMARKS
DATE:
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PROFORMA FOR SITE RESPONSIBILITY SCHEDULE
AREA
COMPLEX:
SCHEDULE:
CONNECTION SITE:
SAFETY
ITEM OF
PLANT/
APPARATUS
PLANT
APPARATUS
OWNER
SITE
MANAGER
SAFETY
RULES
OPERATIONS
CONTROL OR
OTHER
RESPONSIBLE
PERSON
(SAFETY COORDINATOR
OPERATIONAL
PROCEDURES
CONTROL OR
OTHER
RESPONSIBLE
ENGINEER
PARTY
RESPONSIBLE
FOR
UNDERTAKING
STATUTORY
INSPECTIONS,
FAULT
INVESTIGATION
&
MAINTENANCE
REMARKS
NOTES:
SIGNED:
NAME:
COMPANY:
DATE:
SIGNED:
NAME:
COMPANY:
DATE:
SIGNED:
NAME:
COMPANY:
DATE:
SIGNED:
NAME:
COMPANY:
DATE:
PAGE:
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ISSUE NO:
DATE:
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APPENDIX 2 - OPERATION DIAGRAMS
PART 1A - PROCEDURES RELATING TO OPERATION DIAGRAMS
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PART 1B - PROCEDURES RELATING TO GAS ZONE DIAGRAMS
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PART 2 - NON-EXHAUSTIVE LIST OF APPARATUS
TO BE INCLUDED ON OPERATION DIAGRAMS
Basic Principles
(1)
Where practicable, all the HV Apparatus on any Connection Site shall be shown on one
Operation Diagram. Provided the clarity of the diagram is not impaired, the layout shall
represent as closely as possible the geographical arrangement on the Connection Site.
(2)
Where more than one Operation Diagram is unavoidable, duplication of identical
information on more than one Operation Diagram must be avoided.
(3)
The Operation Diagram must show accurately the current status of the Apparatus e.g.
whether commissioned or decommissioned. Where decommissioned, the associated
switchbay will be labelled "spare bay".
(4)
Provision will be made on the Operation Diagram for signifying approvals, together with
provision for details of revisions and dates.
(5)
Operation Diagrams will be prepared in A4 format or such other format as may be agreed
with NGET.
(6)
The Operation Diagram should normally be drawn single line. However, where appropriate,
detail which applies to individual phases shall be shown. For example, some HV Apparatus
is numbered individually per phase.
Apparatus To Be Shown On Operation Diagram
(1)
Busbars
(2)
Circuit Breakers
(3)
Disconnector (Isolator) and Switch Disconnecters (Switching Isolators)
(4)
Disconnectors (Isolators) - Automatic Facilities
(5)
Bypass Facilities
(6)
Earthing Switches
(7)
Maintenance Earths
(8)
Overhead Line Entries
(9)
Overhead Line Traps
(10)
Cable and Cable Sealing Ends
(11)
Generating Unit
(12)
Generator Transformers
(13)
Generating Unit Transformers, Station Transformers, including the lower voltage circuitbreakers.
(14)
Synchronous Compensators
(15)
Static Variable Compensators
(16)
Capacitors (including Harmonic Filters)
(17)
Series or Shunt Reactors (Referred to as "Inductors" at nuclear power station sites)
(18)
Supergrid and Grid Transformers
(19)
Tertiary Windings
(20)
Earthing and Auxiliary Transformers
(21)
Three Phase VT's
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(22)
Single Phase VT & Phase Identity
(23)
High Accuracy VT and Phase Identity
(24)
Surge Arrestors/Diverters
(25)
Neutral Earthing Arrangements on HV Plant
(26)
Fault Throwing Devices
(27)
Quadrature Boosters
(28)
Arc Suppression Coils
(29)
Single Phase Transformers (BR) Neutral and Phase Connections
(30)
Current Transformers (where separate plant items)
(31)
Wall Bushings
(32)
Combined VT/CT Units
(33)
Shorting and Discharge Switches
(34)
Thyristor
(35)
Resistor with Inherent Non-Linear Variability, Voltage Dependent
(36)
Gas Zone
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APPENDIX 3 - MINIMUM FREQUENCY RESPONSE REQUIREMENT
PROFILE AND OPERATING RANGE FOR NEW POWER STATIONS AND
DC CONVERTER STATIONS
CC.A.3.1
Scope
The frequency response capability is defined in terms of Primary Response, Secondary
Response and High Frequency Response. This appendix defines the minimum frequency
response requirement profile for:
(a) each Onshore Generating Unit and/or CCGT Module which has a Completion Date
after 1 January 2001 in England and Wales and 1 April 2005 in Scotland and Offshore
Generating Unit in a Large Power Station,
(b) each DC Converter at a DC Converter Station which has a Completion Date on or
after 1 April 2005 or each Offshore DC Converter which is part of a Large Power
Station.
(c) each Onshore Power Park Module in England and Wales with a Completion Date on
or after 1 January 2006.
(d) each Onshore Power Park Module in operation in Scotland after 1 January 2006 with
a Completion Date after 1 April 2005 and in Power Stations with a Registered
Capacity of 50MW or more.
(e) each Offshore Power Park Module in a Large Power Station with a Registered
Capacity of 50MW or more.
For the avoidance of doubt, this appendix does not apply to:
(i)
Generating Units and/or CCGT Modules which have a Completion Date before 1
January 2001 in England and Wales and before 1 April 2005 in Scotland,
(ii)
DC Converters at a DC Converter Station which have a Completion Date before 1
April 2005.
(iii) Power Park Modules in England and Wales with a Completion Date before 1 January
2006.
(iv) Power Park Modules in operation in Scotland before 1 January 2006.
(v) Power Park Modules in Scotland with a Completion Date before 1 April 2005.
(vi) Power Park Modules in Power Stations with a Registered Capacity less than 50MW.
(vii) Small Power Stations or individually to Power Park Units; or.
(viii) an OTSDUW DC Converter where the Interface Point Capacity is less than 50MW.
OTSDUW Plant and Apparatus should facilitate the delivery of frequency response
services provided by Offshore Generating Units and Offshore Power Park Modules at
the Interface Point.
The functional definition provides appropriate performance criteria relating to the provision of
Frequency control by means of Frequency sensitive generation in addition to the other
requirements identified in CC.6.3.7.
In this Appendix 3 to the CC, for a CCGT Module or a Power Park Module with more than
one Generating Unit, the phrase Minimum Generation applies to the entire CCGT Module
or Power Park Module operating with all Generating Units Synchronised to the System.
The minimum Frequency response requirement profile is shown diagrammatically in Figure
CC.A.3.1. The capability profile specifies the minimum required levels of Primary
Response, Secondary Response and High Frequency Response throughout the normal
plant operating range. The definitions of these Frequency response capabilities are
illustrated diagrammatically in Figures CC.A.3.2 & CC.A.3.3.
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CC.A.3.2
Plant Operating Range
The upper limit of the operating range is the Registered Capacity of the Generating Unit or
CCGT Module or DC Converter or Power Park Module.
The Minimum Generation level may be less than, but must not be more than, 65% of the
Registered Capacity. Each Generating Unit and/or CCGT Module and/or Power Park
Module and/or DC Converter must be capable of operating satisfactorily down to the
Designed Minimum Operating Level as dictated by System operating conditions, although
it will not be instructed to below its Minimum Generation level. If a Generating Unit or
CCGT Module or Power Park Module or DC Converter is operating below Minimum
Generation because of high System Frequency, it should recover adequately to its
Minimum Generation level as the System Frequency returns to Target Frequency so that
it can provide Primary and Secondary Response from Minimum Generation if the
System Frequency continues to fall. For the avoidance of doubt, under normal operating
conditions steady state operation below Minimum Generation is not expected. The
Designed Minimum Operating Level must not be more than 55% of Registered Capacity.
In the event of a Generating Unit or CCGT Module or Power Park Module or DC
Converter load rejecting down to no less than its Designed Minimum Operating Level it
should not trip as a result of automatic action as detailed in BC3.7. If the load rejection is to
a level less than the Designed Minimum Operating Level then it is accepted that the
condition might be so severe as to cause it to be disconnected from the System.
CC.A.3.3
Minimum Frequency Response Requirement Profile
Figure CC.A.3.1 shows the minimum Frequency response requirement profile
diagrammatically for a 0.5 Hz change in Frequency. The percentage response capabilities
and loading levels are defined on the basis of the Registered Capacity of the Generating
Unit or CCGT Module or Power Park Module or DC Converter. Each Generating Unit
and/or CCGT Module and/or Power Park Module and/or DC Converter must be capable of
operating in a manner to provide Frequency response at least to the solid boundaries
shown in the figure. If the Frequency response capability falls within the solid boundaries,
the Generating Unit or CCGT Module or Power Park Module or DC Converter is
providing response below the minimum requirement which is not acceptable. Nothing in this
appendix is intended to prevent a Generating Unit or CCGT Module or Power Park
Module or DC Converter from being designed to deliver a Frequency response in excess
of the identified minimum requirement.
The Frequency response delivered for Frequency deviations of less than 0.5 Hz should be
no less than a figure which is directly proportional to the minimum Frequency response
requirement for a Frequency deviation of 0.5 Hz. For example, if the Frequency deviation
is 0.2 Hz, the corresponding minimum Frequency response requirement is 40% of the level
shown in Figure CC.A.3.1. The Frequency response delivered for Frequency deviations of
more than 0.5 Hz should be no less than the response delivered for a Frequency deviation
of 0.5 Hz.
Each Generating Unit and/or CCGT Module and/or Power Park Module and/or DC
Converter must be capable of providing some response, in keeping with its specific
operational characteristics, when operating between 95% to 100% of Registered Capacity
as illustrated by the dotted lines in Figure CC.A.3.1.
At the Minimum Generation level, each Generating Unit and/or CCGT Module and/or
Power Park Module and/or DC Converter is required to provide high and low frequency
response depending on the System Frequency conditions. Where the Frequency is high,
the Active Power output is therefore expected to fall below the Minimum Generation level.
The Designed Minimum Operating Level is the output at which a Generating Unit and/or
CCGT Module and/or Power Park Module and/or DC Converter has no High Frequency
Response capability. It may be less than, but must not be more than, 55% of the
Registered Capacity. This implies that a Generating Unit or CCGT Module or Power
Park Module or DC Converter is not obliged to reduce its output to below this level unless
the Frequency is at or above 50.5 Hz (cf BC3.7).
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CC.A.3.4
Testing Of Frequency Response Capability
The response capabilities shown diagrammatically in Figure CC.A.3.1 are measured by
taking the responses as obtained from some of the dynamic response tests specified by
NGET and carried out by Generators and DC Converter Station owners for compliance
purposes and to validate the content of Ancillary Services Agreements using an injection
of a Frequency change to the plant control system (i.e. governor and load controller). The
injected signal is a linear ramp from zero to 0.5 Hz Frequency change over a ten second
period, and is sustained at 0.5 Hz Frequency change thereafter, as illustrated
diagrammatically in figures CC.A.3.2 and CC.A.3.3. In the case of an Embedded Medium
Power Station not subject to a Bilateral Agreement or Embedded DC Converter Station
not subject to a Bilateral Agreement, NGET may require the Network Operator within
whose System the Embedded Medium Power Station or Embedded DC Converter
Station is situated, to ensure that the Embedded Person performs the dynamic response
tests reasonably required by NGET in order to demonstrate compliance within the relevant
requirements in the CC.
The Primary Response capability (P) of a Generating Unit or a CCGT Module or Power
Park Module or DC Converter is the minimum increase in Active Power output between 10
and 30 seconds after the start of the ramp injection as illustrated diagrammatically in Figure
CC.A.3.2. This increase in Active Power output should be released increasingly with time
over the period 0 to 10 seconds from the time of the start of the Frequency fall as illustrated
by the response from Figure CC.A.3.2.
The Secondary Response capability (S) of a Generating Unit or a CCGT Module or
Power Park Module or DC Converter is the minimum increase in Active Power output
between 30 seconds and 30 minutes after the start of the ramp injection as illustrated
diagrammatically in Figure CC.A.3.2.
The High Frequency Response capability (H) of a Generating Unit or a CCGT Module or
Power Park Module or DC Converter is the decrease in Active Power output provided 10
seconds after the start of the ramp injection and sustained thereafter as illustrated
diagrammatically in Figure CC.A.3.3. This reduction in Active Power output should be
released increasingly with time over the period 0 to 10 seconds from the time of the start of
the Frequency rise as illustrated by the response in Figure CC.A.3.2.
CC.A.3.5
Repeatability Of Response
When a Generating Unit or CCGT Module or Power Park Module or DC Converter has
responded to a significant Frequency disturbance, its response capability must be fully
restored as soon as technically possible. Full response capability should be restored no
later than 20 minutes after the initial change of System Frequency arising from the
Frequency disturbance.
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Figure CC.A.3.1 - Minimum Frequency Response Requirement Profile for a 0.5 Hz frequency change from
Target Frequency
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Figure CC.A.3.2 - Interpretation of Primary and Secondary Response Values
Figure CC.A.3.3 - Interpretation of High Frequency Response Values
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APPENDIX 4 - FAULT RIDE THROUGH REQUIREMENTS
APPENDIX 4A - FAULT RIDE THROUGH REQUIREMENTS FOR ONSHORE
SYNCHRONOUS GENERATING UNITS, ONSHORE POWER PARK MODULES,
ONSHORE DC CONVERTERS OTSDUW PLANT AND APPARATUS AT THE
INTERFACE POINT, OFFSHORE SYNCHRONOUS GENERATING UNITS IN A LARGE
POWER STATION, OFFSHORE POWER PARK MODULES IN A LARGE POWER
STATION AND OFFSHORE DC CONVERTERS IN A LARGE POWER STATION WHICH
SELECT TO MEET THE FAULT RIDE THROUGH REQUIREMENTS AT THE
INTERFACE POINT
CC.A.4A.1
Scope
The fault ride through requirement is defined in CC.6.3.15.1 (a), (b) and CC.6.3.15.3. This
Appendix provides illustrations by way of examples only of CC.6.3.15.1 (a) (i) and further
background and illustrations to CC.6.3.15.1 (1b) (i) and CC.6.3.15.1 (2b) (i) and is not
intended to show all possible permutations.
CC.A.4A.2
Short Circuit Faults At Supergrid Voltage On The Onshore Transmission System Up To
140ms In Duration
For short circuit faults at Supergrid Voltage on the Onshore Transmission System (which
could be at an Interface Point) up to 140ms in duration, the fault ride through requirement is
defined in CC.6.3.15.1 (a) (i). Figures CC.A.4A.1 (a) and (b) illustrate two typical examples of
voltage recovery for short-circuit faults cleared within 140ms by two circuit breakers (a) and
three circuit breakers (b) respectively.
Figure CC.A.4A.1 (a)
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Figure CC.A.4A.1 (b)
CC.A.4A.3
Supergrid Voltage Dips On The Onshore Transmission System Greater Than 140ms In
Duration
CC.A.4A3.1
Requirements applicable to Synchronous Generating Units subject to Supergrid Voltage
dips on the Onshore Transmission System greater than 140ms in duration.
For balanced Supergrid Voltage dips on the Onshore Transmission System having
durations greater than 140ms and up to 3 minutes, the fault ride through requirement is
defined in CC.6.3.15.1 (1b) and Figure 5a which is reproduced in this Appendix as Figure
CC.A.4A3.1 and termed the voltage–duration profile.
This profile is not a voltage-time response curve that would be obtained by plotting the
transient voltage response at a point on the Onshore Transmission System (or User
System if located Onshore) to a disturbance. Rather, each point on the profile (i.e. the
heavy black line) represents a voltage level and an associated time duration which
connected Synchronous Generating Units must withstand or ride through.
Figures CC.A.4A3.2 (a), (b) and (c) illustrate the meaning of the voltage-duration profile for
voltage dips having durations greater than 140ms.
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Figure CC.A.4A3.1
Figure CC.A.4A3.2 (a)
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Figure CC.A.4A3.2 (b)
Figure CC.A.4A3.2 (c)
CC.A.4A3.2
Requirements applicable to Power Park Modules or OTSDUW Plant and Apparatus
subject to Supergrid Voltage dips on the Onshore Transmission System greater than
140ms in duration
For balanced Supergrid Voltage dips on the Onshore Transmission System (which could
be at an Interface Point) having durations greater than 140ms and up to 3 minutes the fault
ride through requirement is defined in CC.6.3.15.1 (2b) and Figure 5b which is reproduced in
this Appendix as Figure CC.A.4A3.3 and termed the voltage–duration profile.
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This profile is not a voltage-time response curve that would be obtained by plotting the
transient voltage response at a point on the Onshore Transmission System (or User
System if located Onshore) to a disturbance. Rather, each point on the profile (i.e. the
heavy black line) represents a voltage level and an associated time duration which
connected Power Park Modules or OTSDUW Plant and Apparatus must withstand or ride
through.
Figures CC.A.4A.4 (a), (b) and (c) illustrate the meaning of the voltage-duration profile for
voltage dips having durations greater than 140ms.
Figure CC.A.4A3.3
Figure CC.A.4A3.4 (a)
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Figure CC.A.4A3.4 (b)
Figure CC.A.4A3.4 (c)
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APPENDIX 4B - FAULT RIDE THROUGH REQUIREMENTS FOR OFFSHORE
GENERATING UNITS IN A LARGE POWER STATION, OFFSHORE POWER PARK
MODULES IN A LARGE POWER STATION AND OFFSHORE DC CONVERTERS IN A
LARGE POWER STATION WHICH SELECT TO MEET THE FAULT RIDE THROUGH
REQUIREMENTS AT THE LV SIDE OF THE OFFSHORE PLATFORM AS SPECIFIED
IN CC.6.3.15.2
CC.A.4B.1
Scope
The fault ride through requirement is defined in CC.6.3.15.2 (a), (b) and CC.6.3.15.3. This
Appendix provides illustrations by way of examples only of CC.6.3.15.2 (a) (i) and further
background and illustrations to CC.6.3.15.2 (1b) and CC.6.3.15.2 (2b) and is not intended to
show all possible permutations.
CC.A.4B.2
Voltage Dips On The LV Side Of The Offshore Platform Up To 140ms In Duration
For voltage dips on the LV Side of the Offshore Platform which last up to 140ms in
duration, the fault ride through requirement is defined in CC.6.3.15.2 (a) (i). This includes
Figure 6 which is reproduced here in Figure CC.A.4B.1. The purpose of this requirement is
to translate the conditions caused by a balanced or unbalanced fault which occurs on the
Onshore Transmission System (which may include the Interface Point) at the LV Side of
the Offshore Platform.
V/VN is the ratio of the voltage at the LV side of the Offshore Platform to the nominal
voltage of the LV side of the Offshore Platform.
Figure CC.A.4B.1
Figures CC.A.4B.2 (a) and CC.A.4B.2 (b) illustrate two typical examples of the voltage
recovery seen at the LV Side of the Offshore Platform for a short circuit fault cleared within
140ms by (a) two circuit breakers and (b) three circuit breakers on the Onshore
Transmission System.
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Figure CC.A.4B.2 (a)
Figure CC.A.4B.2 (b)
CCA.4B.3
Voltage Dips Which Occur On The LV Side Of The Offshore Platform Greater Than 140ms
In Duration
CC.A.4B.3.1
Requirements applicable to Offshore Synchronous Generating Units subject to voltage
dips which occur on the LV Side of the Offshore Platform greater than 140ms in duration.
In addition to CC.A.4B.2 the fault ride through requirements applicable to Offshore
Synchronous Generating Units during balanced voltage dips which occur at the LV Side
of the Offshore Platform and having durations greater than 140ms and up to 3 minutes are
defined in CC.6.3.15.2 (1b) and Figure 7a which is reproduced in this Appendix as Figure
CC.A.4B3.1 and termed the voltage–duration profile.
This profile is not a voltage-time response curve that would be obtained by plotting the
transient voltage response at the LV Side of the Offshore Platform to a disturbance.
Rather, each point on the profile (i.e. the heavy black line) represents a voltage level and an
associated time duration which connected Offshore Synchronous Generating Units must
withstand or ride through.
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Figures CC.A.4B3.2 (a), (b) and (c) illustrate the meaning of the voltage-duration profile for
voltage dips having durations greater than 140ms.
Figure CC.A.4B3.1
Figure CC.A.4B3.2 (a)
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Figure CC.A.4B3.2 (b)
Figure CC.A.4B3.2 (c)
CC.A.4B.3.2
Requirements applicable to Offshore Power Park Modules subject to Voltage Dips Which
Occur On The LV Side Of The Offshore Platform Greater Than 140ms in Duration.
In addition to CCA.4B.2 the fault ride through requirements applicable for Offshore Power
Park Modules during balanced voltage dips which occur at the LV Side of the Offshore
Platform and have durations greater than 140ms and up to 3 minutes are defined in
CC.6.3.15.2 (2b) (i) and Figure 7b which is reproduced in this Appendix as Figure CC.A.4B.4
and termed the voltage–duration profile.
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This profile is not a voltage-time response curve that would be obtained by plotting the
transient voltage response at the LV Side of the Offshore Platform to a disturbance.
Rather, each point on the profile (i.e. the heavy black line) represents a voltage level and an
associated time duration which connected Offshore Power Park Modules must withstand
or ride through.
Figures CC.A.4B.5 (a), (b) and (c) illustrate the meaning of the voltage-duration profile for
voltage dips having durations greater than 140ms.
Figure CC.A.4B.4
Figure CC.A.4B.5 (a)
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Figure CC.A.4B.5(b)
Figure CC.A.4B.5(c)
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APPENDIX 5 - TECHNICAL REQUIREMENTS
LOW FREQUENCY RELAYS FOR THE AUTOMATIC
DISCONNECTION OF SUPPLIES AT LOW FREQUENCY
CC.A.5.1
Low Frequency Relays
CC.A.5.1.1
The Low Frequency Relays to be used shall have a setting range of 47.0 to 50Hz and be
suitable for operation from a nominal AC input of 63.5, 110 or 240V. The following general
parameters specify the requirements of approved Low Frequency Relays for automatic
st
installations installed and commissioned after 1 April 2007 and provide an indication,
without prejudice to the provisions that may be included in a Bilateral Agreement, for those
st
installed and commissioned before 1 April 2007:
(a) Frequency settings:
47-50Hz in steps of 0.05Hz or better, preferably 0.01Hz;
(b) Operating time:
Relay operating time shall not be more than 150 ms;
(c) Voltage lock-out:
Selectable within a range of 55 to 90% of nominal voltage;
(d) Facility stages:
One or two stages of Frequency operation;
(e) Output contacts:
Two output contacts per stage to be capable of repetitively
making and breaking for 1000 operations:
(f) Accuracy:
0.01 Hz maximum error under reference environmental and
system voltage conditions.
0.05 Hz maximum error at 8% of total harmonic distortion
Electromagnetic Compatibility Level.
CC.A.5.2
Low Frequency Relay Voltage Supplies
CC.A.5.2.1
It is essential that the voltage supply to the Low Frequency Relays shall be derived from
the primary System at the supply point concerned so that the Frequency of the Low
Frequency Relays input voltage is the same as that of the primary System. This requires
either:
(a) the use of a secure supply obtained from voltage transformers directly associated with
the grid transformer(s) concerned, the supply being obtained where necessary via a
suitable automatic voltage selection scheme; or
(b) the use of the substation 240V phase-to-neutral selected auxiliary supply, provided that
this supply is always derived at the supply point concerned and is never derived from a
standby supply Generating Unit or from another part of the User System.
CC.A.5.3
Scheme Requirements
CC.A.5.3.1
The tripping facility should be engineered in accordance with the following reliability
considerations:
(a) Dependability
Failure to trip at any one particular Demand shedding point would not harm the overall
operation of the scheme. However, many failures would have the effect of reducing the
amount of Demand under low Frequency control. An overall reasonable minimum
requirement for the dependability of the Demand shedding scheme is 96%, i.e. the
average probability of failure of each Demand shedding point should be less than 4%.
Thus the Demand under low Frequency control will not be reduced by more than 4%
due to relay failure.
(b) Outages
Low Frequency Demand shedding schemes will be engineered such that the amount
of Demand under control is as specified in Table CC.A.5.5.1a and is not reduced
unacceptably during equipment outage or maintenance conditions.
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CC.A.5.3.2
The total operating time of the scheme, including circuit breakers operating time, shall where
reasonably practicable, be less than 200 ms. For the avoidance of doubt, the replacement of
plant installed prior to October 2009 will not be required in order to achieve lower total
scheme operating times.
CC.A.5.4
Low Frequency Relay Testing
CC.A.5.4.1
Low Frequency Relays installed and commissioned after 1 January 2007 shall be type
tested in accordance with and comply with the functional test requirements for Frequency
Protection contained in Energy Networks Association Technical Specification 48-6-5 Issue 1
dated 2005 “ENA Protection Assessment Functional Test Requirements – Voltage and
Frequency Protection”.
st
st
For the avoidance of doubt, Low Frequency Relays installed and commissioned before 1
January 2007 shall comply with the version of CC.A.5.1.1 applicable at the time such Low
Frequency Relays were commissioned.
CC.A.5.5
Scheme Settings
CC.A.5.5.1
Table CC.A.5.5.1a shows, for each Transmission Area, the percentage of Demand (based
on Annual ACS Conditions) at the time of forecast National Electricity Transmission
System peak Demand that each Network Operator whose System is connected to the
Onshore Transmission System within such Transmission Area shall disconnect by Low
Frequency Relays at a range of frequencies. Where a Network Operator’s System is
connected to the National Electricity Transmission System in more than one
Transmission Area, the settings for the Transmission Area in which the majority of the
Demand is connected shall apply.
Frequency Hz
% Demand disconnection for each Network Operator in
Transmission Area
NGET
SPT
SHETL
48.8
5
48.75
5
48.7
10
48.6
7.5
48.5
7.5
10
48.4
7.5
10
10
48.2
7.5
10
10
48.0
5
10
10
47.8
5
Total % Demand
60
40
40
10
Table CC.A.5.5.1a
Note – the percentages in table CC.A.5.5.1a are cumulative such that, for example, should
the frequency fall to 48.6 Hz in the NGET Transmission Area, 27.5% of the total Demand
connected to the National Electricity Transmission System in the NGET Transmission
Area shall be disconnected by the action of Low Frequency Relays.
The percentage Demand at each stage shall be allocated as far as reasonably practicable.
The cumulative total percentage Demand is a minimum.
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APPENDIX 6 - PERFORMANCE REQUIREMENTS FOR CONTINUOUSLY
ACTING AUTOMATIC EXCITATION CONTROL SYSTEMS FOR
ONSHORE SYNCHRONOUS GENERATING UNITS
CC.A.6.1
Scope
CC.A.6.1.1
This Appendix sets out the performance requirements of continuously acting automatic
excitation control systems for Onshore Synchronous Generating Units that must be
complied with by the User. This Appendix does not limit any site specific requirements that
may be included in a Bilateral Agreement where in NGET's reasonable opinion these
facilities are necessary for system reasons.
CC.A.6.1.2
Where the requirements may vary the likely range of variation is given in this Appendix. It
may be necessary to specify values outside this range where NGET identifies a system
need, and notwithstanding anything to the contrary NGET may specify in the Bilateral
Agreement values outside of the ranges provided in this Appendix 6. The most common
variations are in the on-load excitation ceiling voltage requirements and the response time
required of the Exciter. Actual values will be included in the Bilateral Agreement.
CC.A.6.1.3
Should a Generator anticipate making a change to the excitation control system it shall
notify NGET under the Planning Code (PC.A.1.2(b) and (c)) as soon as the Generator
anticipates making the change. The change may require a revision to the Bilateral
Agreement.
CC.A.6.2
Requirements
CC.A.6.2.1
The Excitation System of an Onshore Synchronous Generating Unit shall include an
excitation source (Exciter), a Power System Stabiliser and a continuously acting
Automatic Voltage Regulator (AVR) and shall meet the following functional specification.
CC.A.6.2.2
In respect of Onshore Synchronous Generating Units with a Completion Date on or after
1 January 2009, and Onshore Synchronous Generating Units with a Completion Date
before 1 January 2009 subject to a Modification to the excitation control facilities where the
Bilateral Agreement does not specify otherwise, the continuously acting automatic
excitation control system shall include a Power System Stabiliser (PSS) as a means of
supplementary control. The functional specification of the Power System Stabiliser is
included in CC.A.6.2.5.
CC.A.6.2.3
Steady State Voltage Control
CC.A.6.2.3.1
An accurate steady state control of the Onshore Generating Unit pre-set terminal voltage is
required. As a measure of the accuracy of the steady-state voltage control, the Automatic
Voltage Regulator shall have static zero frequency gain, sufficient to limit the change in
terminal voltage to a drop not exceeding 0.5% of rated terminal voltage, when the Onshore
Generating Unit output is gradually changed from zero to rated MVA output at rated
voltage, Active Power and Frequency.
CC.A.6.2.4
Transient Voltage Control
CC.A.6.2.4.1
For a step change from 90% to 100% of the nominal Onshore Generating Unit terminal
voltage, with the Onshore Generating Unit on open circuit, the Excitation System
response shall have a damped oscillatory characteristic. For this characteristic, the time for
the Onshore Generating Unit terminal voltage to first reach 100% shall be less than 0.6
seconds. Also, the time to settle within 5% of the voltage change shall be less than 3
seconds.
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CC.A.6.2.4.2
To ensure that adequate synchronising power is maintained, when the Onshore Generating
Unit is subjected to a large voltage disturbance, the Exciter whose output is varied by the
Automatic Voltage Regulator shall be capable of providing its achievable upper and lower
limit ceiling voltages to the Onshore Generating Unit field in a time not exceeding that
specified in the Bilateral Agreement. This will normally be not less than 50 ms and not
greater than 300 ms. The achievable upper and lower limit ceiling voltages may be
dependent on the voltage disturbance.
CC.A.6.2.4.3
The Exciter shall be capable of attaining an Excitation System On Load Positive Ceiling
Voltage of not less than a value specified in the Bilateral Agreement that will be:
not less than 2 per unit (pu)
normally not greater than 3 pu
exceptionally up to 4 pu
of Rated Field Voltage when responding to a sudden drop in voltage of 10 percent or more
at the Onshore Generating Unit terminals. NGET may specify a value outside the above
limits where NGET identifies a system need.
CC.A.6.2.4.4
If a static type Exciter is employed:
(i)
the field voltage should be capable of attaining a negative ceiling level specified in the
Bilateral Agreement after the removal of the step disturbance of CC.A.6.2.4.3. The
specified value will be 80% of the value specified in CC.A.6.2.4.3. NGET may specify a
value outside the above limits where NGET identifies a system need.
(ii)
the Exciter must be capable of maintaining free firing when the Onshore Generating
Unit terminal voltage is depressed to a level which may be between 20% to 30% of
rated terminal voltage
(iii) the Exciter shall be capable of attaining a positive ceiling voltage not less than 80% of
the Excitation System On Load Positive Ceiling Voltage upon recovery of the
Onshore Generating Unit terminal voltage to 80% of rated terminal voltage following
fault clearance. NGET may specify a value outside the above limits where NGET
identifies a system need.
(iv) The requirement to provide a separate power source for the Exciter will be specified in
the Bilateral Agreement if NGET identifies a Transmission System need.
CC.A.6.2.5
Power Oscillations Damping Control
CC.A.6.2.5.1
To allow the Onshore Generating Unit to maintain second and subsequent swing stability
and also to ensure an adequate level of low frequency electrical damping power, the
Automatic Voltage Regulator shall include a Power System Stabiliser as a means of
supplementary control.
CC.A.6.2.5.2
Whatever supplementary control signal is employed, it shall be of the type which operates
into the Automatic Voltage Regulator to cause the field voltage to act in a manner which
results in the damping power being improved while maintaining adequate synchronising
power.
CC.A.6.2.5.3
The arrangements for the supplementary control signal shall ensure that the Power System
Stabiliser output signal relates only to changes in the supplementary control signal and not
the steady state level of the signal. For example, if generator electrical power output is
chosen as a supplementary control signal then the Power System
Stabiliser output
should relate only to changes in generator electrical power output and not the steady state
level of power output. Additionally the Power System Stabiliser should not react to
mechanical power changes in isolation for example during rapid changes in steady state
load or when providing frequency response.
CC.A.6.2.5.4
The output signal from the Power System Stabiliser shall be limited to not more than ±10%
of the Onshore Generating Unit terminal voltage signal at the Automatic Voltage
Regulator input. The gain of the Power System Stabiliser shall be such that an increase in
the gain by a factor of 3 shall not cause instability.
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CC.A.6.2.5.5
The Power System Stabiliser shall include elements that limit the bandwidth of the output
signal. The bandwidth limiting must ensure that the highest frequency of response cannot
excite torsional oscillations on other plant connected to the network. A bandwidth of 0-5Hz
would be judged to be acceptable for this application.
CC.A.6.2.5.6
The Generator will agree Power System Stabiliser settings with NGET prior to the on-load
commissioning detailed in BC2.11.2(d). To allow assessment of the performance before onload commissioning the Generator will provide to NGET a report covering the areas
specified in CP.A.3.2.1.
CC.A.6.2.5.7
The Power System Stabiliser must be active within the Excitation System at all times
when Synchronised including when the Under Excitation Limiter or Over Excitation
Limiter are active. When operating at low load when Synchronising or De-Synchronising
an Onshore Generating Unit, the Power System Stabiliser may be out of service.
CC.A.6.2.5.8
Where a Power System Stabiliser is fitted to a Pumped Storage Unit it must function
when the Pumped Storage Unit is in both generating and pumping modes.
CC.A.6.2.6
Overall Excitation System Control Characteristics
CC.A.6.2.6.1
The overall Excitation System shall include elements that limit the bandwidth of the output
signal. The bandwidth limiting must be consistent with the speed of response requirements
and ensure that the highest frequency of response cannot excite torsional oscillations on
other plant connected to the network. A bandwidth of 0-5 Hz will be judged to be acceptable
for this application.
CC.A.6.2.6.2
The response of the Automatic Voltage Regulator combined with the Power System
Stabiliser shall be demonstrated by injecting similar step signal disturbances into the
Automatic Voltage Regulator reference as detailed in OC5A.2.2 and OC5.A.2.4. The
Automatic Voltage Regulator shall include a facility to allow step injections into the
Automatic Voltage Regulator voltage reference, with the Onshore Generating Unit
operating at points specified by NGET (up to rated MVA output). The damping shall be
judged to be adequate if the corresponding Active Power response to the disturbances
decays within two cycles of oscillation.
CC.A.6.2.6.3
A facility to inject a band limited random noise signal into the Automatic Voltage Regulator
voltage reference shall be provided for demonstrating the frequency domain response of the
Power System Stabiliser. The tuning of the Power System Stabiliser shall be judged to be
adequate if the corresponding Active Power response shows improved damping with the
Power System Stabiliser in combination with the Automatic Voltage Regulator compared
with the Automatic Voltage Regulator alone over the frequency range 0.3Hz – 2Hz.
CC.A.6.2.7
Under-Excitation Limiters
CC.A.6.2.7.1
The security of the power system shall also be safeguarded by means of MVAr Under
Excitation Limiters fitted to the generator Excitation System. The Under Excitation
Limiter shall prevent the Automatic Voltage Regulator reducing the generator excitation to
a level which would endanger synchronous stability. The Under Excitation Limiter shall
operate when the excitation system is providing automatic control. The Under Excitation
Limiter shall respond to changes in the Active Power (MW) and the Reactive Power
(MVAr), and to the square of the generator voltage in such a direction that an increase in
voltage will permit an increase in leading MVAr. The characteristic of the Under Excitation
Limiter shall be substantially linear from no-load to the maximum Active Power output of
the Onshore Generating Unit at any setting and shall be readily adjustable.
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CC.A.6.2.7.2
The performance of the Under Excitation Limiter shall be independent of the rate of
change of the Onshore Generating Unit load and shall be demonstrated by testing as
detailed in OC5.A.2.5. The resulting maximum overshoot in response to a step injection
which operates the Under Excitation Limiter shall not exceed 4% of the Onshore
Generating Unit rated MVA. The operating point of the Onshore Generating Unit shall be
returned to a steady state value at the limit line and the final settling time shall not be greater
than 5 seconds. When the step change in Automatic Voltage Regulator reference voltage
is reversed, the field voltage should begin to respond without any delay and should not be
held down by the Under Excitation Limiter. Operation into or out of the preset limit levels
shall ensure that any resultant oscillations are damped so that the disturbance is within 0.5%
of the Onshore Generating Unit MVA rating within a period of 5 seconds.
CC.A.6.2.7.3
The Generator shall also make provision to prevent the reduction of the Onshore
Generating Unit excitation to a level which would endanger synchronous stability when the
Excitation System is under manual control.
CC.A.6.2.8
Over-Excitation Limiters
CC.A.6.2.8.1
The settings of the Over-Excitation Limiter, where it exists, shall ensure that the generator
excitation is not limited to less than the maximum value that can be achieved whilst ensuring
the Onshore Generating Unit is operating within its design limits. If the generator excitation
is reduced following a period of operation at a high level, the rate of reduction shall not
exceed that required to remain within any time dependent operating characteristics of the
Onshore Generating Unit.
CC.A.6.2.8.2
The performance of the Over-Excitation Limiter, where it exists, shall be demonstrated by
testing as described in OC5.A.2.6. Any operation beyond the Over-Excitation Limit shall be
controlled by the Over-Excitation Limiter without the operation of any Protection that could
trip the Onshore Generating Unit.
CC.A.6.2.8.3
The Generator shall also make provision to prevent any over-excitation restriction of the
generator when the Excitation System is under manual control, other than that necessary
to ensure the Onshore Generating Unit is operating within its design limits.
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APPENDIX 7 - PERFORMANCE REQUIREMENTS FOR CONTINUOUSLY
ACTING AUTOMATIC VOLTAGE CONTROL SYSTEMS FOR ONSHORE
NON-SYNCHRONOUS GENERATING UNITS, ONSHORE DC
CONVERTERS, ONSHORE POWER PARK MODULES AND OTSDUW
PLANT AND APPARATUS AT THE INTERFACE POINT
CC.A.7.1
Scope
CC.A.7.1.1
This Appendix sets out the performance requirements of continuously acting automatic
voltage control systems for Onshore Non-Synchronous Generating Units, Onshore DC
Converters, Onshore Power Park Modules and OTSDUW Plant and Apparatus at the
Interface Point that must be complied with by the User. This Appendix does not limit any
site specific requirements that may be included in a Bilateral Agreement where in NGET's
reasonable opinion these facilities are necessary for system reasons.
CC.A.7.1.2
Proposals by Generators to make a change to the voltage control systems are required to
be notified to NGET under the Planning Code (PC.A.1.2(b) and (c)) as soon as the
Generator anticipates making the change. The change may require a revision to the
Bilateral Agreement.
CC.A.7.2
Requirements
CC.A.7.2.1
NGET requires that the continuously acting automatic voltage control system for the
Onshore Non-Synchronous Generating Unit, Onshore DC Converter or Onshore Power
Park Module or OTSDUW Plant and Apparatus shall meet the following functional
performance specification. If a Network Operator has confirmed to NGET that its network to
which an Embedded Onshore Non-Synchronous Generating Unit, Onshore DC
Converter, Onshore Power Park Module or OTSDUW Plant and Apparatus is connected
is restricted such that the full reactive range under the steady state voltage control
requirements (CC.A.7.2.2) cannot be utilised, NGET may specify in the Bilateral Agreement
alternative limits to the steady state voltage control range that reflect these restrictions.
Where the Network Operator subsequently notifies NGET that such restriction has been
removed, NGET may propose a Modification to the Bilateral Agreement (in accordance
with the CUSC contract) to remove the alternative limits such that the continuously acting
automatic voltage control system meets the following functional performance specification.
All other requirements of the voltage control system will remain as in this Appendix.
CC.A.7.2.2
Steady State Voltage Control
CC.A.7.2.2.1
The Onshore Non-Synchronous Generating Unit, Onshore DC Converter, Onshore
Power Park Module or OTSDUW Plant and Apparatus shall provide continuous steady
state control of the voltage at the Onshore Grid Entry Point (or Onshore User System
Entry Point if Embedded) (or the Interface Point in the case of OTSDUW Plant and
Apparatus) with a Setpoint Voltage and Slope characteristic as illustrated in Figure
CC.A.7.2.2a. It should be noted that where the Reactive Power capability requirement of a
directly connected Onshore Non-Synchronous Generating Unit, Onshore DC Converter,
Onshore Power Park Module in Scotland, or OTSDUW Plant and Apparatus in Scotland
as specified in CC.6.3.2 (c), is not at the Onshore Grid Entry Point or Interface Point, the
values of Qmin and Qmax shown in this figure will be as modified by the 33/132kV or
33/275kV or 33/400kV transformer.
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Figure CC.A.7.2.2a
CC.A.7.2.2.2
The continuously acting automatic control system shall be capable of operating to a
Setpoint Voltage between 95% and 105% with a resolution of 0.25% of the nominal voltage.
For the avoidance of doubt values of 95%, 95.25%, 95.5% … may be specified, but not
intermediate values. The initial Setpoint Voltage will be 100%. The tolerance within which
this Setpoint Voltage shall be achieved is specified in BC2.A.2.6. For the avoidance of
doubt, with a tolerance of 0.25% and a Setpoint Voltage of 100%, the achieved value shall
be between 99.75% and 100.25%. NGET may request the Generator to implement an
alternative Setpoint Voltage within the range of 95% to 105%. For Embedded Generators
the Setpoint Voltage will be discussed between NGET and the relevant Network Operator
and will be specified to ensure consistency with CC.6.3.4.
CC.A.7.2.2.3
The Slope characteristic of the continuously acting automatic control system shall be
adjustable over the range 2% to 7% (with a resolution of 0.5%). For the avoidance of doubt
values of 2%, 2.5%, 3% may be specified, but not intermediate values. The initial Slope
setting will be 4%. The tolerance within which this Slope shall be achieved is specified in
BC2.A.2.6. For the avoidance of doubt, with a tolerance of 0.5% and a Slope setting of 4%,
the achieved value shall be between 3.5% and 4.5%. NGET may request the Generator to
implement an alternative slope setting within the range of 2% to 7%. For Embedded
Generators the Slope setting will be discussed between NGET and the relevant Network
Operator and will be specified to ensure consistency with CC.6.3.4.
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Figure CC.A.7.2.2b
Figure CC.A.7.2.2c
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CC.A.7.2.2.4
Figure CC.A.7.2.2b shows the required envelope of operation for Onshore NonSynchronous Generating Units, Onshore DC Converters, OTSDUW Plant and
Apparatus and Onshore Power Park Modules except for those Embedded at 33kV and
below or directly connected to the National Electricity Transmission System at 33kV and
below. Figure CC.A.7.2.2c shows the required envelope of operation for Onshore NonSynchronous Generating Units, Onshore DC Converters and Onshore Power Park
Modules Embedded at 33kV and below or directly connected to the National Electricity
Transmission System at 33kV and below. Where the Reactive Power capability
requirement of a directly connected Onshore Non-Synchronous Generating Unit,
Onshore DC Converter, OTSDUW Plant and Apparatus or Onshore Power Park Module
in Scotland, as specified in CC.6.3.2 (c), is not at the Onshore Grid Entry Point or
Interface Point in the case of OTSDUW Plant and Apparatus, the values of Qmin and
Qmax shown in this figure will be as modified by the 33/132kV or 33/275kV or 33/400kV
transformer. The enclosed area within points ABCDEFGH is the required capability range
within which the Slope and Setpoint Voltage can be changed.
CC.A.7.2.2.5
Should the operating point of the Onshore Non-Synchronous Generating Unit, Onshore
DC Converter, OTSDUW Plant and Apparatus or Onshore Power Park Module deviate
so that it is no longer a point on the operating characteristic (figure CC.A.7.2.2a) defined by
the target Setpoint Voltage and Slope, the continuously acting automatic voltage control
system shall act progressively to return the value to a point on the required characteristic
within 5 seconds.
CC.A.7.2.2.6
Should the Reactive Power output of the Onshore Non-Synchronous Generating Unit,
Onshore DC Converter, OTSDUW Plant and Apparatus or Onshore Power Park Module
reach its maximum lagging limit at a Onshore Grid Entry Point voltage (or Onshore User
System Entry Point voltage if Embedded or Interface Point in the case of OTSDUW Plant
and Apparatus) above 95%, the Onshore Non-Synchronous Generating Unit, Onshore
DC Converter, OTSDUW Plant and Apparatus or Onshore Power Park Module shall
maintain maximum lagging Reactive Power output for voltage reductions down to 95%. This
requirement is indicated by the line EF in figures CC.A.7.2.2b and CC.A.7.2.2c. Should the
Reactive Power output of the Onshore Non-Synchronous Generating Unit, Onshore DC
Converter, OTSDUW Plant and Apparatus or Onshore Power Park Module reach its
maximum leading limit at a Onshore Grid Entry Point voltage (or Onshore User System
Entry Point voltage if Embedded or Interface Point in the case of OTSDUW Plant and
Apparatus) below 105%, the Onshore Non-Synchronous Generating Unit, Onshore DC
Converter, OTSDUW Plant and Apparatus or Onshore Power Park Module shall
maintain maximum leading Reactive Power output for voltage increases up to 105%. This
requirement is indicated by the line AB in figures CC.A.7.2.2b and CC.A.7.2.2c.
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CC.A.7.2.2.7
For Onshore Grid Entry Point voltages (or Onshore User System Entry Point voltages if
Embedded or Interface Point voltages) below 95%, the lagging Reactive Power capability
of the Onshore Non-Synchronous Generating Unit, Onshore DC Converter, OTSDUW
Plant and Apparatus or Onshore Power Park Module should be that which results from
the supply of maximum lagging reactive current whilst ensuring the current remains within
design operating limits. An example of the capability is shown by the line DE in figures
CC.A.7.2.2b and CC.A.7.2.2c. For Onshore Grid Entry Point voltages (or User System
Entry Point voltages if Embedded or Interface Point voltages) above 105%, the leading
Reactive Power capability of the Onshore Non-Synchronous Generating Unit, Onshore
DC Converter, OTSDUW Plant and Apparatus or Onshore Power Park Module should
be that which results from the supply of maximum leading reactive current whilst ensuring
the current remains within design operating limits. An example of the capability is shown by
the line AH in figures CC.A.7.2.2b and CC.A.7.2.2c. Should the Reactive Power output of
the Onshore Non-Synchronous Generating Unit, Onshore DC Converter, OTSDUW
Plant and Apparatus or Onshore Power Park Module reach its maximum lagging limit at
an Onshore Grid Entry Point voltage (or Onshore User System Entry Point voltage if
Embedded or Interface Point in the case of OTSDUW Plant and Apparatus) below 95%,
the Onshore Non-Synchronous Generating Unit, Onshore DC Converter or Onshore
Power Park Module shall maintain maximum lagging reactive current output for further
voltage decreases. Should the Reactive Power output of the Onshore Non-Synchronous
Generating Unit, Onshore DC Converter, OTSDUW Plant and Apparatus or Onshore
Power Park Module reach its maximum leading limit at a Onshore Grid Entry Point
voltage (or User System Entry Point voltage if Embedded or Interface Point voltage in
the case of an OTSDUW Plant and Apparatus) above 105%, the Onshore NonSynchronous Generating Unit, Onshore DC Converter, OTSDUW Plant and Apparatus
or Onshore Power Park Module shall maintain maximum leading reactive current output for
further voltage increases.
CC.A.7.2.2.8
All OTSDUW Plant and Apparatus must be capable of enabling Users undertaking
OTSDUW to comply with an instruction received from NGET relating to a variation of the
Setpoint Voltage at the Interface Point within 2 minutes of such instruction being received.
CC.A.7.2.2.9
For OTSDUW Plant and Apparatus connected to a Network Operator’s System where
the Network Operator has confirmed to NGET that its System is restricted in accordance
with CC.A.7.2.1, clause CC.A.7.2.2.8 will not apply unless NGET can reasonably
demonstrate that the magnitude of the available change in Reactive Power has a significant
effect on voltage levels on the Onshore National Electricity Transmission System.
CC.A.7.2.3
Transient Voltage Control
CC.A.7.2.3.1
For an on-load step change in Onshore Grid Entry Point or Onshore User System Entry
Point voltage, or in the case of OTSDUW Plant and Apparatus an on-load step change in
Transmission Interface Point voltage, the continuously acting automatic control system
shall respond according to the following minimum criteria:
(i)
the Reactive Power output response of the Onshore Non-Synchronous Generating
Unit, Onshore DC Converter, OTSDUW Plant and Apparatus or Onshore Power
Park Module shall commence within 0.2 seconds of the application of the step. It shall
progress linearly although variations from a linear characteristic shall be acceptable
provided that the MVAr seconds delivered at any time up to 1 second are at least those
that would result from the response shown in figure CC.A.7.2.3.1a.
(ii)
the response shall be such that 90% of the change in the Reactive Power output of the
Onshore Non-Synchronous Generating Unit, Onshore DC Converter, OTSDUW
Plant and Apparatus or Onshore Power Park Module, will be achieved within

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1 second, where the step is sufficiently large to require a change in the steady
state Reactive Power output from zero to its maximum leading value or
maximum lagging value, as required by CC.6.3.2 (or, if appropriate,
CC.A.7.2.2.6 or CC.A.7.2.2.7); and
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
2 seconds, for Plant and Apparatus installed on or after 1 December 2017,
where the step is sufficiently large to require a change in the steady state
Reactive Power output from its maximum leading value to its maximum lagging
value or vice versa.
(iii) the magnitude of the Reactive Power output response produced within 1 second shall
vary linearly in proportion to the magnitude of the step change.
(iv) within 2 seconds from achieving 90% of the response as defined in CC.A.7.2.3.1 (ii), the
peak to peak magnitude of any oscillations shall be less than 5% of the change in
steady state Reactive Power.
(v) following the transient response, the conditions of CC.A.7.2.2 apply.
MVArs
Required response at 1
second
0.2
CC.A.7.2.3.2
Figure CC.A.7.2.3.1a
1
Seconds
An Onshore Non-Synchronous Generating Unit, Onshore DC Converter, OTSDUW
Plant and Apparatus or Onshore Power Park Module installed on or after 1 December
2017 shall be capable of
(a)
changing its Reactive Power output from its maximum lagging value to its maximum
leading value, or vice versa, then reverting back to the initial level of Reactive Power
output once every 15 seconds for at least 5 times within any 5 minute period; and
(b)
changing its Reactive Power output from zero to its maximum leading value then
reverting back to zero Reactive Power output at least 25 times within any 24 hour
period and from zero to its maximum lagging value then reverting back to zero
Reactive Power output at least 25 times within any 24 hour period. Any subsequent
restriction on reactive capability shall be notified to NGET in accordance with
BC2.5.3.2, and BC2.6.1.
In all cases, the response shall be in accordance to CC.A.7.2.3.1 where the change in
Reactive Power output is in response to an on-load step change in Onshore Grid Entry
Point or Onshore User System Entry Point voltage, or in the case of OTSDUW Plant and
Apparatus an on-load step change in Transmission Interface Point voltage.
CC.A.7.2.4
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CC.A.7.2.4.1
The requirement for the continuously acting voltage control system to be fitted with a Power
System Stabiliser (PSS) shall be specified in the Bilateral Agreement if, in NGET’s view,
this is required for system reasons. However if a Power System Stabiliser is included in
the voltage control system its settings and performance shall be agreed with NGET and
commissioned in accordance with BC2.11.2. To allow assessment of the performance
before on-load commissioning the Generator will provide to NGET a report covering the
areas specified in CP.A.3.2.2.
CC.A.7.2.5
Overall Voltage Control System Characteristics
CC.A.7.2.5.1
The continuously acting automatic voltage control system is required to respond to minor
variations, steps, gradual changes or major variations in Onshore Grid Entry Point voltage
(or Onshore User System Entry Point voltage if Embedded or Interface Point voltage in
the case of OTSDUW Plant and Apparatus).
CC.A.7.2.5.2
The overall voltage control system shall include elements that limit the bandwidth of the
output signal. The bandwidth limiting must be consistent with the speed of response
requirements and ensure that the highest frequency of response cannot excite torsional
oscillations on other plant connected to the network. A bandwidth of 0-5Hz would be judged
to be acceptable for this application. All other control systems employed within the Onshore
Non-Synchronous Generating Unit, Onshore DC Converter, OTSDUW Plant and
Apparatus or Onshore Power Park Module should also meet this requirement
CC.A.7.2.5.3
The response of the voltage control system (including the Power System Stabiliser if
employed) shall be demonstrated by testing in accordance with OC5A.A.3.
< END OF CONNECTION CONDITIONS >
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COMPLIANCE PROCESSES
(CP)
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
CP.1 INTRODUCTION ................................................................................................................................... 2
CP.2 OBJECTIVE .......................................................................................................................................... 2
CP.3 SCOPE ................................................................................................................................................. 2
CP.4 CONNECTION PROCESS .................................................................................................................... 3
CP.5 ENERGISATION OPERATIONAL NOTIFICATION ............................................................................... 3
CP.6 INTERIM OPERATIONAL NOTIFICATION ........................................................................................... 4
CP.7 FINAL OPERATIONAL NOTIFICATION ................................................................................................ 7
CP.8 LIMITED OPERATIONAL NOTIFICATION ............................................................................................ 9
CP.9 PROCESSES RELATING TO DEROGATIONS .................................................................................. 12
CP.10 MANUFACTURER’S DATA & PERFORMANCE REPORT ............................................................... 12
APPENDIX 1 - ILLUSTRATIVE PROCESS DIAGRAMS ................................................................................ 15
APPENDIX 2 - USER SELF CERTIFICATION OF COMPLIANCE ................................................................. 20
APPENDIX 3 - SIMULATION STUDIES ......................................................................................................... 21
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CP.1
INTRODUCTION
CP.1.1
The Compliance Processes ("CP") specifies:
the process (leading to an Energisation Operational Notification) which must be followed
by NGET and any User to demonstrate its compliance with the Grid Code in relation to its
Plant and Apparatus (including OTSUA) prior to the relevant Plant and Apparatus
(including any OTSUA) being energised.
the process (leading to an Interim Operational Notification and Final Operational
Notification) which must be followed by NGET and any Generator or DC Converter
Station owner to demonstrate its compliance with the Grid Code in relation to its Plant and
Apparatus (including any dynamically controlled OTSUA). This process shall be followed
prior to and during the course of the relevant Plant and Apparatus (including OTSUA) being
energised and Synchronised.
the process (leading to a Limited Operational Notification) which must be followed by
NGET and each Generator and DC Converter Station owner where any of its Plant and/or
Apparatus (including any OTSUA) becomes unable to comply with relevant provisions of
the Grid Code, and where applicable with Appendices F1 to F5 (and in the case of OTSUA,
Appendices OF1 to OF5 of the Bilateral Agreement). This process also includes when
changes or Modifications are made to Plant and/or Apparatus (including OTSUA). This
process applies to such Plant and/or Apparatus after the Plant and/or Apparatus has
become Operational and until Disconnected from the Total System, (or until, in the case
of OTSUA, the OTSUA Transfer Time), when changes or Modifications are made.
CP.1.2
As used in this CP references to OTSUA means OTSUA to be connected or connected to
the National Electricity Transmission System prior to the OTSUA Transfer Time.
CP1.3
Where the Generator or DC Convertor Station Owner and/or NGET are required to apply
for a derogation from the Authority, this is not in respect of the OTSUA
CP.2
OBJECTIVE
CP.2.1
The objective of the CP is to ensure that there is a clear and consistent process for
demonstration of compliance by Users with the Connection Conditions and Bilateral
Agreement which are similar for all Users of an equivalent category and will enable NGET
to comply with its statutory and Transmission Licence obligations.
CP.2.2
Provisions of the CP which apply in relation to OTSDUW and OTSUA shall (in any particular
case) apply up to the OTSUA Transfer Time, whereupon such provisions shall (without
prejudice to any prior non-compliance) cease to apply.
CP.2.3
In relation to OTSDUW, provisions otherwise to be contained in a Bilateral Agreement may
be contained in the Construction Agreement, and accordingly a reference in the CP to a
relevant Bilateral Agreement includes the relevant Construction Agreement.
CP.3
SCOPE
CP.3.1
The CP applies to NGET and to Users, which in the CP means:
(a) Generators (other than in relation to Embedded Small Power Stations or Embedded
Medium Power Stations not subject to a Bilateral Agreement) including those
undertaking OTSDUW.
(b) Network Operators;
(c) Non-Embedded Customers;
(d) DC Converter Station owners (other than those which only have Embedded DC
Converter Stations not subject to a Bilateral Agreement).
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CP.3.2
The above categories of User will become bound by the CP prior to them generating,
distributing, supplying or consuming, or in the case of OTSUA, transmitting, as the case may
be, and references to the various categories should, therefore, be taken as referring to them
in that prospective role as well as to Users actually connected.
CP.4
CONNECTION PROCESS
CP.4.1
The CUSC Contract(s) contain certain provisions relating to the procedure for connection to
the National Electricity Transmission System or, in the case of Embedded Power
Stations or Embedded DC Converter Stations, becoming operational and include
provisions to be complied with by Users prior to and during the course of NGET notifying the
User that it has the right to become operational. In addition to such provisions this CP sets
out in further detail the processes to be followed to demonstrate compliance. Whilst this CP
does not expressly address the processes to be followed in the case of OTSUA connecting
to a Network Operator’s User System prior to the OTSUA Transfer Time, the processes
to be followed by NGET and the Generator in respect of OTSUA in such circumstances
shall be consistent with those set out below by reference OTSUA directly connected to the
National Electricity Transmission System.
CP.4.2
The provisions contained in CP.5 to CP.7 detail the process to be followed in order for the
User’s Plant and Apparatus (including OTSUA) to become operational. This process
includes EON (energisation) ION (interim synchronising) and FON (final).
CP.4.2.1
The provisions contained in CP.5 relate to the connection and energisation of User’s Plant
and Apparatus (including OTSUA) to the National Electricity Transmission System or
where Embedded, to a User’s System and is shown diagrammatically at CP.A.1.1.
CP.4.2.2
The provisions contained in CP.6 and CP.7 provide the process for Generators and DC
Converter Station owners to demonstrate compliance with the Grid Code and with, where
applicable, the CUSC Contract(s) prior to and during the course of such Generator’s or DC
Converter Station owner’s Plant and Apparatus (including OTSUA up to the OTSUA
Transfer Time) becoming operational and is shown diagrammatically at CP.A.1.2 and
CP.A.1.3.
CP.4.2.3
The provisions contained in CP.8 detail the process to be followed when:
(a) a Generator or DC Converter Station owner’s Plant and/or Apparatus (including the
OTSUA) is unable to comply with any provisions of the Grid Code and Bilateral
Agreement; or,
(b) following any notification by a Generator or a DC Converter Station owner under the
PC of any change to its Plant and Apparatus (including any OTSUA); or,
(c) a Modification to a Generator or a DC Converter Station owner’s Plant and/or
Apparatus.
The process is shown diagrammatically at Appendix CP.A.1.4 for condition (a) and Appendix
CP.A.1.5 for conditions (b) and (c)
CP.4.3
Embedded Medium Power Stations not subject to a Bilateral Agreement and Embedded DC
Converter Stations not subject to a Bilateral Agreement
CP.4.3.1
For the avoidance of doubt the process in this CP does not apply to Embedded Medium
Power Stations not subject to a Bilateral Agreement and Embedded DC Converter
Stations not subject to a Bilateral Agreement.
CP.5
ENERGISATION OPERATIONAL NOTIFICATION
CP.5.1
The following provisions apply in relation to the issue of an Energisation Operational
Notification.
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CP.5.1.1
Certain provisions relating to the connection and energisation of the User’s Plant and
Apparatus at the Connection Site and OTSUA at the Transmission Interface Point and
in certain cases of Embedded Plant and Apparatus are specified in the CUSC and/or
CUSC Contract(s). For other Embedded Plant and Apparatus the Distribution Code, the
DCUSA and the Embedded Development Agreement for the connection specify equivalent
provisions. Further detail on this is set out in CP.5 below.
CP.5.2
The items for submission prior to the issue of an Energisation Operational Notification are
set out in CC.5.2
CP.5.3
In the case of a Generator or DC Converter Station owner the items referred to in CC.5.2
shall be submitted using the User Data File Structure.
CP.5.4
Not less than 28 days, or such shorter period as may be acceptable in NGET’s reasonable
opinion, prior to the User wishing to energise its Plant and Apparatus (including passive
OTSUA) for the first time the User will submit to NGET a Certificate of Readiness to
Energise High Voltage Equipment which specifies the items of Plant and Apparatus
(including OTSUA) ready to be energised in a form acceptable to NGET.
CP.5.5
If the relevant obligations under the provisions of the CUSC and/or CUSC Contract(s) and
the conditions of CP.5 have been completed to NGET’s reasonable satisfaction then NGET
shall issue an Energisation Operational Notification. Any dynamically controlled reactive
compensation OTSUA (including Statcoms or Static Var Compensators) shall not be
Energised until the appropriate Interim Operational Notification has been issued in
accordance with CP.6.
CP.6
INTERIM OPERATIONAL NOTIFICATION
CP.6.1
The following provisions apply in relation to the issue of an Interim Operational
Notification.
CP.6.2
Not less than 28 days, or such shorter period as may be acceptable in NGET’s reasonable
opinion, prior to the Generator or DC Converter Station owner wishing to Synchronise its
Plant and Apparatus or dynamically controlled OTSUA for the first time the Generator or
DC Converter Station owner will:
(i)
submit to NGET a Notification of User’s Intention to Synchronise; and
(iI) submit to NGET the items referred to at CP.6.3.
CP.6.3
Items for submission prior to issue of the Interim Operational Notification.
CP.6.3.1
Prior to the issue of an Interim Operational Notification in respect of the User’s Plant and
Apparatus or dynamically controlled OTSUA.
the Generator or DC Converter Station owner must submit to NGET to NGET’s
satisfaction:
(a) updated Planning Code data (both Standard Planning Data and Detailed Planning
Data), with any estimated values assumed for planning purposes confirmed or, where
practical, replaced by validated actual values and by updated estimates for the future
and by updated forecasts for Forecast Data items such as Demand;
(b) details of any special Power Station, Generating Unit(s), Power Park Module(s) or
DC Converter Station(s) protection as applicable. This may include Pole Slipping
protection and islanding protection schemes;
(c) any items required by CP.5.2, updated by the User as necessary;
(d) simulation study provisions of Appendix CP.A.3 and the results demonstrating
compliance with Grid Code requirements of:
PC.A.5.4.2
PC.A.5.4.3.2,
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CC.6.3.4,
CC.6.3.7(c)(i),
CC.6.3.15,
CC.A.6.2.5.6,
CC.A.7.2.3.1,
as applicable to the Power Station, Generating Unit(s), Power Park Module(s) or DC
Converter(s) or dynamically controlled OTSUA unless agreed otherwise by NGET;
(e) a detailed schedule of the tests and the procedures for the tests required to be carried
out by the Generator or DC Converter Station owner under CP.7.2 to demonstrate
compliance with relevant Grid Code requirements. Such schedule to be consistent with
Appendix OC5.A.2 (in the case of Generating Units other than Power Park Modules)
or Appendix OC5.A.3 (in the case of Generating Units comprising Power Park
Modules) and OTSUA as applicable); and
(f)
an interim Compliance Statement and a User Self Certification of Compliance
completed by the User (including any Unresolved Issues) against the relevant Grid
Code requirements including details of any requirements that the Generator or DC
Converter Station owner has identified that will not or may not be met or
demonstrated.
CP.6.3.2
The items referred to in CP.6.3 shall be submitted by the Generator or DC Converter
Station owner using the User Data File Structure.
CP.6.4
No Generating Unit, CCGT Module, Power Park Module or DC Converter or dynamically
controlled OTSUA shall be Synchronised to the Total System (and for the avoidance of
doubt, dynamically controlled OTSUA will not be able to transmit), until the later of:
(a) the date specified by NGET in the Interim Operational Notification issued in respect
of the Generating Unit(s), CCGT Module(s), Power Park Module(s) or DC
Converter(s) or dynamically controlled OTSUA; and,
(b) if Embedded, the date of receipt of a confirmation from the Network Operator in
whose System the Plant and Apparatus is connected that it is acceptable to the
Network Operator that the Plant and Apparatus be connected and Synchronised;
and,
(c) in the case of Synchronous Generating Unit(s) only after the date of receipt by
Generator of written confirmation from NGET that the Generating Unit or CCGT
Module as applicable has completed the following tests to demonstrate compliance with
the relevant provisions of the Connection Conditions to NGET’s satisfaction:
(i)
those tests required to establish the open and short circuit saturation
characteristics of the Generating Unit (as detailed in Appendix OC5.A.2.3) to
enable assessment of the short circuit ratio in accordance with CC.6.3.2. Such
tests may be carried out at a location other than the Power Station site; and
(ii)
open circuit step response tests (as detailed in Appendix OC5.A.2.2) to
demonstrate compliance with CC.A.6.2.4.1.
CP.6.5
NGET shall assess the schedule of tests submitted by the Generator or DC Converter
Station owner with the Notification of User’s Intention to Synchronise under CP.6.1 and
shall determine whether such schedule has been completed to NGET’s satisfaction.
CP.6.6
When the requirements of CP.6.2 to CP.6.5 have been met, NGET will notify the Generator
or DC Converter Station owner that the:
Generating Unit,
CCGT Module,
Power Park Module,
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Dynamically controlled OTSUA or
DC Converter,
as applicable may (subject to the Generator or DC Converter Station owner having fulfilled
the requirements of CP.6.3 where that applies) be Synchronised to the Total System
through the issue of an Interim Operational Notification. Where the Generator is
undertaking OTSDUW then the Interim Operational Notification will be in two parts, with
the “Interim Operational Notification Part A” applicable to the OTSUA and the “Interim
Operational Notification Part B” applicable to the Users Plant and Apparatus. For the
avoidance of doubt, the Interim Operational Notification Part A and the Interim
Operational Notification Part B can be issued together or at different times. In respect of
an Embedded Power Station or Embedded DC Converter Station (other than a
Embedded Medium Power Stations not subject to a Bilateral Agreement and Embedded
DC Converter Stations not subject to a Bilateral Agreement), NGET will notify the
Network Operator that an Interim Operational Notification has been issued.
CP.6.6.1
The Interim Operational Notification will be time limited, the expiration date being specified
at the time of issue. The Interim Operational Notification may be renewed by NGET.
CP.6.6.2
The Generator or DC Converter Station owner must operate the Generating Unit, CCGT
Module, Power Park Module, OTSUA or DC Converter in accordance with the terms,
arising from the Unresolved Issues, of the Interim Operational Notification. Where
practicable, NGET will discuss such terms with the Generator or DC Converter Station
owner prior to including them in the Interim Operational Notification.
CP.6.6.3
The Interim Operational Notification will include the following limitations:
(a) In the case of OTSUA, the Interim Operational Notification Part A permits
Synchronisation of the dynamically controlled OTSUA to the Total System only for
the purposes of active control of voltage and reactive power and not for the purpose of
exporting Active Power.
(b) In the case of a Power Park Module the Interim Operational Notification (and where
OTSDUW Arrangements apply, this reference will be to the Interim Operational
Notification Part B) will limit the proportion of the Power Park Module which can be
simultaneously Synchronised to the Total System such that neither of the following
figures is exceeded:
(i)
20% of the Registered Capacity of the Power Park Module (or the output of a
single Power Park Unit where this exceeds 20% of the Power Station’s
Registered Capacity); nor
(ii)
50MW
until the Generator has completed the voltage control tests (detailed in OC5.A.3.2)
(including in respect of any dynamically controlled OTSUA) to NGET’s reasonable
satisfaction. Following successful completion of this test each additional Power Park
Unit should be included in the voltage control scheme as soon as is technically possible
(unless NGET agrees otherwise).
(b) In the case of a Power Park Module with a Registered Capacity greater or equal to
100MW, the Interim Operational Notification (and where OTSDUW Arrangements
apply, this reference will be to the Interim Operational Notification Part B) will limit
the proportion of the Power Park Module which can be simultaneously Synchronised
to the Total System to 70% of Registered Capacity until the Generator has
completed the Limited Frequency Sensitive Mode control tests with at least 50% of
the Registered Capacity of the Power Park Module in service (detailed in OC5.A.3.3)
to NGET’s reasonable satisfaction.
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(c) In the case of a Synchronous Generating Unit employing a static Excitation System
the Interim Operational Notification (and where OTSDUW Arrangements apply, this
reference will be to the Interim Operational Notification Part B) may if applicable limit
the maximum Active Power output and reactive power output of the Synchronous
Generating Unit or CCGT module prior to the successful commissioning of the Power
System Stabiliser to NGET’s satisfaction.
CP.6.6.4
When a User and NGET are acting/operating in accordance with the provisions of a Interim
Operational Notification, whilst it is in force, the relevant provisions of the Grid Code to
which that Interim Operational Notification relates will not apply to the User or NGET to
the extent and for the period set out in the Interim Operational Notification.
CP.6.7
Other than Unresolved Issues that are subject to tests required under CP.7.2 to be
witnessed by NGET, the Generator or DC Converter Station owner must resolve any
Unresolved Issues prior to the commencement of the tests, unless NGET agrees to a later
resolution. The Generator or DC Converter Station owner must liaise with NGET in
respect of such resolution. The tests that may be witnessed by NGET are specified in
CP.7.2.
CP.6.8
Not less than 28 days, or such shorter period as may be acceptable in NGET’s reasonable
opinion, prior to the Generator or DC Converter Station owner wishing to commence tests
required under CP.7 to be witnessed by NGET, the Generator or DC Converter Station
owner will notify NGET that the Generating Unit(s), CCGT Module(s), Power Park
Module(s) or DC Converter(s) as applicable is ready to commence such tests.
CP.6.9
The items referred to at CP.7.3 shall be submitted by the Generator or the DC Converter
Station owner after successful completion of the tests required under CP.7.2.
CP.7.
FINAL OPERATIONAL NOTIFICATION
CP.7.1
The following provisions apply in relation to the issue of a Final Operational Notification.
CP.7.2
Tests to be carried out prior to issue of the Final Operational Notification
CP.7.2.1
Prior to the issue of a Final Operational Notification the Generator or DC Converter
Station owner must have completed the tests specified in this CP.7.2.2 to NGET’s
satisfaction to demonstrate compliance with the relevant Grid Code provisions.
CP.7.2.2
In the case of any Generating Unit, CCGT Module, Power Park Module, OTSUA (if
applicable) and DC Converter these tests will comprise one or more of the following:
(a) reactive capability tests to demonstrate that the Generating Unit, CCGT Module,
Power Park Module, OTSUA (if applicable) and DC Converter can meet the
requirements of CC.6.3.2. These may be witnessed by NGET on site if there is no
metering to the NGET Control Centre.
(b) voltage control system tests to demonstrate that the Generating Unit, CCGT Module,
Power Park Module, OTSUA (if applicable) and DC Converter can meet the
requirements of CC.6.3.6, CC.6.3.8 and, in the case of Power Park Module, OTSUA (if
applicable) and DC Converter, the requirements of CC.A.7 and, in the case of
Generating Unit and CCGT Module, the requirements of CC.A.6, and any terms
specified in the Bilateral Agreement as applicable. These tests may also be used to
validate the Excitation System model (PC.A.5.3) or voltage control system model
(PC.A.5.4) as applicable. These tests may be witnessed by NGET.
(c) governor or frequency control system tests to demonstrate that the Generating Unit,
CCGT Module, OTSUA (if applicable) and Power Park Module can meet the
requirements of CC.6.3.6, CC.6.3.7, where applicable CC.A.3, and BC.3.7. The results
will also validate the Mandatory Service Agreement required by CC.8.1. These tests
may also be used to validate the Governor model (PC.A.5.3) or frequency control
system model (PC.A.5.4) as applicable. These tests may be witnessed by NGET.
Issue 5 Revision 15
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(d) fault ride through tests in respect of a Power Station with a Registered Capacity of
100MW or greater, comprised of one or more Power Park Modules, to demonstrate
compliance with CC.6.3.15 (a), (b) and (c), CC.A.4.1, CC.A.4.2 and CC.A.4.3. Where
test results from a Manufacturers Data & Performance Report as defined in CP.10
have been accepted this test will not be required.
(e) any further tests reasonably required by NGET and agreed with the User to
demonstrate any aspects of compliance with the Grid Code and the CUSC Contracts.
CP.7.2.3
NGET’s preferred range of tests to demonstrate compliance with the CC are specified in
Appendix OC5.A.2 (in the case of Generating Units other than Power Park Modules) or
Appendix OC5.A.3 (in the case of Generating Units comprising Power Park Modules or
OTSUA if applicable) or Appendix OC5.A.4 (in the case of DC Converters) and are to be
carried out by the User with the results of each test provided to NGET. The User may carry
out an alternative range of tests if this is agreed with NGET. NGET may agree a reduced set
of tests where there is a relevant Manufacturers Data & Performance Report as detailed
in CP.10.
CP.7.2.4
In the case of Offshore Power Park Modules which do not contribute to Offshore
Transmission Licensee Reactive Power capability as described in CC.6.3.2(e)(i) or
CC.6.3.2(e)(ii) or Voltage Control as described in CC.6.3.8(b)(i) the tests outlined in CP.7.2.2
(a) and CP.7.2.2 (b) are not required. However, the offshore reactive power transfer tests
outlined in OC5.A.2.8 shall be completed in their place.
CP.7.2.5
Following completion of each of the tests specified in this CP.7.2, NGET will notify the
Generator or DC Converter Station owner whether, in the opinion of NGET, the results
demonstrate compliance with the relevant Grid Code conditions.
CP.7.2.6
The Generator or DC Converter Station owner is responsible for carrying out the tests and
retains the responsibility for safety and personnel during the test.
CP.7.3
Items for submission prior to issue of the Final Operational Notification
CP.7.3.1
Prior to the issue of a Final Operational Notification the Generator or DC Converter
Station owner must submit to NGET to NGET’s satisfaction:
(a) updated Planning Code data (both Standard Planning Data and Detailed Planning
Data), with validated actual values and updated estimates for the future including
Forecast Data items such as Demand;
(b) any items required by CP.5.2 and CP.6.3, updated by the User as necessary;
(c) evidence to NGET’s satisfaction that demonstrates that the controller models and/or
parameters (as required under PC.A.5.3.2(c) option 2, PC.A.5.3.2(d) option 2,
PC.A.5.4.2, and/or PC.A.5.4.3.2) supplied to NGET provide a reasonable representation
of the behaviour of the User’s Plant and Apparatus and OTSUA if applicable;
(d) results from the tests required in accordance with CP.7.2 carried out by the Generator
to demonstrate compliance with relevant Grid Code requirements including the tests
witnessed by NGET; and
(e) the final Compliance Statement and a User Self Certification of Compliance signed
by the User and a statement of any requirements that the Generator or DC Converter
Station owner has identified that have not been met together with a copy of the
derogation in respect of the same from the Authority.
CP.7.3.2
Issue 5 Revision 15
The items in CP.7.3 should be submitted by the Generator (including in respect of any
OTSUA if applicable) or DC Converter Station owner using the User Data File Structure.
CP
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CP.7.4
If the requirements of CP.7.2 and CP.7.3 have been successfully met, NGET will notify the
Generator or DC Converter Station owner that compliance with the relevant Grid Code
provisions has been demonstrated for the Generating Unit(s), CCGT Module(s), Power
Park Module(s), OTSUA, if applicable or DC Converter(s) as applicable through the issue
of a Final Operational Notification. In respect of a Embedded Power Station or
Embedded DC Converter Station other than a Embedded Medium Power Stations not
subject to a Bilateral Agreement and Embedded DC Converter Stations not subject to a
Bilateral Agreement, NGET will notify the Network Operator that a Final Operational
Notification has been issued.
CP.7.5
If a Final Operational Notification can not be issued because the requirements of CP.7.2
and CP.7.3 have not been successfully met prior to the expiry of an Interim Operational
Notification then the Generator or DC Converter Station owner (where licensed in respect
of its activities) and/or NGET shall apply to the Authority for a derogation. The provisions of
CP.9 shall then apply.
CP.8
LIMITED OPERATIONAL NOTIFICATION
CP.8.1
Following the issue of a Final Operational Notification if:
(i)
the Generator or DC Converter Station owner becomes aware, that its Plant and/or
Apparatus’ (including OTSUA if applicable) capability to meet any provisions of the
Grid Code, or where applicable the Bilateral Agreement is not fully available then the
Generator or DC Converter Station owner shall follow the process in CP.8.2 to
CP.8.11; or,
(ii)
a Network Operator becomes aware, that the capability of Plant and/or Apparatus’
belonging to a Embedded Power Station or Embedded DC Converter Station (other
than a Embedded Medium Power Stations not subject to a Bilateral Agreement and
Embedded DC Converter Stations not subject to a Bilateral Agreement) is failing to
meet any provisions of the Grid Code, or where applicable the Bilateral Agreement
then the Network Operator shall inform NGET and NGET shall inform the Generator
or DC Converter Station owner and then follow the process in CP.8.2 to CP.8.11; or,
(iii) NGET becomes aware through monitoring as described in OC5.4, that a Generator or
DC Converter Station owner Plant and/or Apparatus’ (including OTSUA if applicable)
capability to meet any provisions of the Grid Code, or where applicable the Bilateral
Agreement is not fully available then NGET shall inform the other party. Where NGET
and the Generator or DC Converter Station owner cannot agree from the monitoring
as described in OC5.4 whether the Plant and/or Apparatus (including OTSUA if
applicable) is fully available and/or is compliant with the requirements of the Grid Code
and where applicable the Bilateral Agreement, the parties shall first apply the process
in OC5.5.1, before applying the process defined in CP.8 (LON) if applicable. Where the
testing instructed in accordance with OC.5.5.1 indicates that the Plant and/or
Apparatus (including OTSUA if applicable) is not fully available and/or is not compliant
with the requirements of the Grid Code and/or the Bilateral Agreement, or if the parties
so agree, the process in CP.8.2 to CP.8.11 shall be followed.
CP.8.2
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Immediately upon a Generator or DC Converter Station owner becoming aware that its
Generating Unit, CCGT Module, Power Park Module, OTSUA (if applicable) or DC
Converter Station as applicable may be unable to comply with certain provisions of the Grid
Code or (where applicable) the Bilateral Agreement, the Generator or DC Converter
Station owner shall notify NGET in writing. Additional details of any operating restrictions or
changes in applicable data arising from the potential non-compliance and an indication of the
date from when the restrictions will be removed and full compliance demonstrated shall be
provided as soon as reasonably practical.
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CP.8.3
If the nature of any unavailability and/or potential non-compliance described in CP.8.1
causes or can reasonably be expected to cause a material adverse effect on the business or
condition of NGET or other Users or the National Electricity Transmission System or any
User Systems then NGET may, notwithstanding the provisions of this CP.8 follow the
provisions of Paragraph 5.4 of the CUSC.
CP.8.4
Except where the provisions of CP.8.3 apply, where the restriction notified in CP.8.2 is not
resolved in 28 days then the Generator or DC Converter Station owner with input from and
discussion of conclusions with NGET, and the Network Operator where the Generating
Unit, CCGT Module, Power Park Module or Power Station as applicable is Embedded,
shall undertake an investigation to attempt to determine the causes of and solution to the
non-compliance. Such investigation shall continue for no longer than 56 days. During such
investigation the Generator or DC Converter Station owner shall provide to NGET the
relevant data which has changed due to the restriction in respect of CP.7.3.1 as notified to
the Generator or DC Converter Station owner by NGET as being required to be provided.
CP.8.5
Issue and Effect of LON
CP.8.5.1
Following the issue of a Final Operational Notification, NGET will issue to the Generator
or DC Converter Station owner a Limited Operational Notification if:
(a) by the end of the 56 day period referred to at CP.8.4, the investigation has not resolved
the non-compliance to NGET’s satisfaction; or
(b) NGET is notified by a Generator or DC Converter Station owner of a Modification to
its Plant and Apparatus (including OTSUA if applicable); or
(c) NGET receives a submission of data, or a statement from a Generator or DC
Converter Station owner indicating a change in Plant or Apparatus (including OTSUA
if applicable) or settings (including but not limited to governor and excitation control
systems) that may in NGETs reasonable opinion, acting in accordance with Good
Industry Practice be expected to result in a material change of performance.
In the case of an Embedded Generator or Embedded DC Converter Station owner,
NGET will issue a copy of the Limited Operational Notification to the Network Operator.
CP.8.5.2
The Limited Operational Notification will be time limited to expire no later than 12 months
from the start of the non-compliance or restriction or from reconnection following a change.
NGET may agree a longer duration in the case of a Limited Operational Notification
following a Modification or whilst the Authority is considering the application for a
derogation in accordance with CP.9.1.
CP.8.5.3
The Limited Operational Notification will notify the Generator or DC Converter Station
owner of any restrictions on the operation of the Generating Unit(s), CCGT Module(s),
Power Park Module(s), OTSUA (if applicable) or DC Converter(s) and will specify the
Unresolved Issues. The Generator or DC Converter Station owner must operate in
accordance with any notified restrictions and must resolve the Unresolved Issues.
CP.8.5.4
When a User and NGET are acting/operating in accordance with the provisions of a Limited
Operational Notification, whilst it is in force, the relevant provisions of the Grid Code to
which that Limited Operational Notification relates will not apply to the User or NGET to
the extent and for the period set out in the Limited Operational Notification.
CP.8.5.5
The Unresolved Issues included in a Limited Operational Notification will show the
extent that the provisions of CP.7.2 (testing) and CP.7.3 (final data submission) shall apply.
In respect of selecting the extent of any tests which may in NGET’s view reasonably be
needed to demonstrate the restored capability and in agreeing the time period in which the
tests will be scheduled, NGET shall, where reasonably practicable, take account of the
Generator or DC Converter Station owner’s input to contain its costs associated with the
testing.
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CP.8.5.6
In the case of a change or Modification the Limited Operational Notification may specify
that the affected Plant and/or Apparatus (including OTSUA if applicable) or associated
Generating Unit(s) or Power Park Unit(s) must not be Synchronised until all of the
following items, that in NGET’s reasonable opinion are relevant, have been submitted to
NGET to NGET’s satisfaction:
(a) updated Planning Code data (both Standard Planning Data and Detailed Planning
Data);
(b) details of any relevant special Power Station, Generating Unit(s), Power Park
Module(s), OTSUA (if applicable) or DC Converter Station(s) protection as applicable.
This may include Pole Slipping protection and islanding protection schemes; and
(c) simulation study provisions of Appendix CP.A.3 and the results demonstrating
compliance with Grid Code requirements relevant to the change or Modification as
agreed by NGET; and
(d) a detailed schedule of the tests and the procedures for the tests required to be carried
out by the Generator or DC Converter Station to demonstrate compliance with
relevant Grid Code requirements as agreed by NGET. The schedule of tests shall be
consistent with Appendix OC5.A.2 or Appendix OC5.A.3 as appropriate; and
(e) an interim Compliance Statement and a User Self Certification of Compliance
completed by the User (including any Unresolved Issues) against the relevant Grid
Code requirements including details of any requirements that the Generator or DC
Converter Station owner has identified that will not or may not be met or
demonstrated; and
(f)
any other items specified in the LON.
CP.8.5.7
The items referred to in CP.8.5.6 shall be submitted by the Generator (including in respect
of any OTSUA if applicable) or DC Converter Station owner using the User Data File
Structure.
CP.8.5.8
In the case of Synchronous Generating Unit(s) only, the Unresolved Issues of the LON
may require that the Generator must complete the following tests to NGET’s satisfaction to
demonstrate compliance with the relevant provisions of the CCs prior to the Generating Unit
being Synchronised to the Total System:
(a) those tests required to establish the open and short circuit saturation characteristics of
the Generating Unit (as detailed in Appendix OC5.A.2.3) to enable assessment of the
short circuit ratio in accordance with CC.6.3.2. Such tests may be carried out at a
location other than the Power Station site; and
(b) open circuit step response tests (as detailed in Appendix OC5.A.2.2) to demonstrate
compliance with CC.A.6.2.4.1.
CP.8.6
CP.8.7
Issue 5 Revision 15
In the case of a change or Modification, not less than 28 days, or such shorter period as
may be acceptable in NGET’s reasonable opinion, prior to the Generator or DC Converter
Station owner wishing to Synchronise its Plant and Apparatus (including OTSUA if
applicable) for the first time following the change or Modification, the Generator or DC
Converter Station owner will:
(i)
submit a Notification of User’s Intention to Synchronise; and
(ii)
submit to NGET the items referred to at CP.8.5.6.
Other than Unresolved Issues that are subject to tests to be witnessed by NGET, the
Generator or DC Converter Station owner must resolve any Unresolved Issues prior to
the commencement of the tests, unless NGET agrees to a later resolution. The Generator
or DC Converter Station owner must liaise with NGET in respect of such resolution. The
tests that may be witnessed by NGET are specified in CP.7.2.2.
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CP.8.8
Not less than 28 days, or such shorter period as may be acceptable in NGET’s reasonable
opinion, prior to the Generator or DC Converter Station owner wishing to commence tests
listed as Unresolved Issues to be witnessed by NGET, the Generator or DC Converter
Station owner will notify NGET that the Generating Unit(s), CCGT Module(s), Power Park
Module(s), OTSUA (if applicable) or DC Converter(s) as applicable is ready to commence
such tests.
CP.8.9
The items referred to at CP.7.3 and listed as Unresolved Issues shall be submitted by the
Generator or the DC Converter Station owner after successful completion of the tests.
CP.8.10
Where the Unresolved Issues have been resolved a Final Operational Notification will be
issued to the User.
CP.8.11
If a Final Operational Notification has not been issued by NGET within the 12 month
period referred to at CP.8.5.2 (or where agreed following a Modification by the expiry time
of the LON) then the Generator or DC Converter Station owner (where licensed in respect
of its activities) and NGET shall apply to the Authority for a derogation.
CP.9
PROCESSES RELATING TO DEROGATIONS
CP.9.1
Whilst the Authority is considering the application for a derogation, the Interim Operational
Notification or Limited Operational Notification will be extended to remain in force until
the Authority has notified NGET and the Generator or DC Converter Station owner of its
decision. Where the Generator or DC Converter Station owner is not licensed NGET may
propose any necessary changes to the Bilateral Agreement with such unlicensed
Generator or DC Converter Station owner.
CP.9.2
If the Authority:
(a) grants a derogation in respect of the Plant and/or Apparatus, then NGET shall issue
Final Operational Notification once all other Unresolved Issues are resolved; or
(b) decides a derogation is not required in respect of the Plant and/or Apparatus then
NGET will reconsider the relevant Unresolved Issues and may issue a Final
Operational Notification once all other Unresolved Issues are resolved; or
(c) decides not to grant any derogation in respect of the Plant and/or Apparatus, then
there will be no Operational Notification in place and NGET and the User shall
consider its rights pursuant to the CUSC.
CP.9.3
Where an Interim Operational Notification or Limited Operational Notification is so
conditional upon a derogation and such derogation includes any conditions (including any
time limit to such derogation) the Generator or DC Converter Station owner will progress
the resolution of any Unresolved Issues and / or progress and / or comply with any
conditions upon such derogation and the provisions of CP.6.9 to CP.7.4 shall apply and shall
be followed.
CP.10
MANUFACTURER’S DATA & PERFORMANCE REPORT
CP.10.1.1
Data and performance characteristics in respect of certain Grid Code requirements may be
registered with NGET by Power Park Unit manufacturers in respect of specific models of
Power Park Units by submitting information in the form of a Manufacturer’s Data and
Performance Report to NGET.
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CP.10.1.2
A Generator planning to construct a new Power Station containing the appropriate version
of Power Park Units in respect of which a Manufacturer’s Data & Performance Report
has been submitted to NGET may reference the Manufacturer’s Data & Performance
Report in its submissions to NGET.
Any Generator considering referring to a
Manufacturer’s Data & Performance Report for any aspect of its Plant and Apparatus
may contact NGET to discuss the suitability of the relevant Manufacturer’s Data &
Performance Report to its project to determine if, and to what extent, the data included in
the Manufacturer’s Data & Performance Report contributes towards demonstrating
compliance with those aspects of the Grid Code applicable to the Generator. NGET will
inform the Generator if the reference to the Manufacturer’s Data & Performance Report is
not appropriate or not sufficient for its project.
CP.10.1.3
The process to be followed by Power Park Unit manufacturers submitting a Manufacturer’s
Data & Performance Report is agreed by NGET. CP.10.2 indicates the specific Grid Code
requirement areas in respect of which a Manufacturer’s Data & Performance Report may
be submitted.
CP.10.1.4
NGET will maintain and publish a register of those Manufacturer’s Data & Performance
Reports which NGET has received and accepted as being an accurate representation of the
performance of the relevant Plant and / or Apparatus. Such register will identify the
manufacturer, the model(s) of Power Park Unit(s) to which the report applies and the
provisions of the Grid Code in respect of which the report contributes towards the
demonstration of compliance. The inclusion of any report in the register does not in any way
confirm that any Power Park Modules which utilise any Power Park Unit(s) covered by a
report is or will be compliant with the Grid Code.
CP.10.2
A Manufacturer’s Data & Performance Report in respect of Power Park Units may cover
one (or part of one) or more of the following provisions of the Grid Code:
(a) Fault Ride Through capability CC.6.3.15
(b) Power Park Module mathematical model PC.A.5.4.2
CP.10.3
Reference to a Manufacturer’s Data & Performance Report in a User’s submissions does
not by itself constitute compliance with the Grid Code.
CP.10.4
A Generator referencing a Manufacturer’s Data & Performance Report should insert the
relevant Manufacturer’s Data & Performance Report reference in the appropriate place in
the DRC data submission and / or in the User Data File Structure. NGET will consider the
suitability of a Manufacturer’s Data & Performance Report:
(a) in place of DRC data submissions a mathematical model suitable for representation of
the entire Power Park Module as per CP.A.3.4.4. For the avoidance of doubt only the
relevant sections as specified in PC.A.2.5.5.7 apply. Site specific parameters will still
need to be submitted by the Generator.
(b) in place of Fault simulation studies as follows;
NGET will not require Fault Ride Through simulation studies to be conducted as per
CP.A.3.5.1 and qualified in CP.A.3.5.2 provided that;
(i)
Adequate and relevant Power Park Unit data is included in respect of Fault Ride
Through testing covered in CP.A.14.7.1 in the relevant Manufacturer’s Data &
Performance Report , and
(ii)
For each type and duration of fault as detailed in CP.A.3.5.1, the expected
minimum retained voltage is greater than the corresponding minimum voltage
achieved and successfully ridden through in the fault ride through tests covered by
the Manufacturer’s Data & Performance Report.
(c) to reduce the scope of compliance site tests as follows;
(i)
Issue 5 Revision 15
Where there is a Manufacturer’s Data & Performance Report in respect of a
Power Park Unit which covers Fault Ride Through, NGET may agree that no Fault
Ride Through testing is required.
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CP.10.5
It is the responsibility of the User to ensure that the correct reference for the Manufacturer’s
Data & Performance Report is used and the User by using that reference accepts
responsibility for the accuracy of the information. The User shall ensure that the
manufacturer has kept NGET informed of any relevant variations in plant specification since
the submission of the relevant Manufacturer’s Data & Performance Report which could
impact on the validity of the information.
CP.10.6
NGET may contact the Power Park Unit manufacturer directly to verify the relevance of the
use of such Manufacturer’s Data & Performance Report. If NGET believe the use some
or all of such Manufacturer’s Data & Performance Report information is incorrect or the
referenced data is inappropriate then the reference to the Manufacturer’s Data &
Performance Report may be declared invalid by NGET. Where, and to the extent possible,
the data included in the Manufacturer’s Data & Performance Report is appropriate, the
compliance assessment process will be continued using the data included in the
Manufacturer’s Data & Performance Report.
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APPENDIX 1 - ILLUSTRATIVE PROCESS DIAGRAMS
CP.A.1.1 Illustrative Compliance Process for Energisation of a User
The process illustrated in CP.A.1.1 applies to all Users energising passive network Plant and Apparatus
including Distribution Network Operators, Non-embedded Customers, Generators and DC Converter
Station owners. This process is a subset of the full process for Generators and DC Converter Station
owners shown in CP.A.1.2. This diagram illustrates the process in the CP and includes references in
brackets to specific Grid Code clauses.
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CP.A.1.2 Illustrative Compliance Process for New Power Stations/DC Converter Stations
This diagram illustrates the process in the CP and includes references in brackets to specific Grid Code
clauses. For the avoidance of doubt this process does not apply to Embedded Medium Power Stations not
subject to a Bilateral Agreement and Embedded DC Converter Stations not subject to a Bilateral
Agreement.
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CP.A.1.3 Illustrative Compliance Process for New Offshore Power Stations and OTSUA
This diagram illustrates the process in the CP and includes references in brackets to specific Grid Code
clauses.
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CP.A.1.4 Illustrative Compliance Process for Ongoing Compliance
This diagram illustrates the process in the CP and includes references in brackets to specific Grid Code
clauses. For the avoidance of doubt this process does not apply to Embedded Medium Power Stations not
subject to a Bilateral Agreement and Embedded DC Converter Stations not subject to a Bilateral
Agreement.
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CP.A.1.5 Illustrative Compliance Process for Modification or change
This diagram illustrates the process in the CP and includes references in brackets to specific Grid Code
clauses. For the avoidance of doubt this process does not apply to Embedded Medium Power Stations not
subject to a Bilateral Agreement and Embedded DC Converter Stations not subject to a Bilateral
Agreement.
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APPENDIX 2 - USER SELF CERTIFICATION OF COMPLIANCE
USER SELF CERTIFICATION OF COMPLIANCE (Interim/Final)
Power Station/ DC
Converter Station:
[Name of Connection Site/site of connection]
OTSUA
[Name of Interface Site]
User:
[Full User name]
Registered Capacity
(MW) of Plant:
This User Self Certification of Compliance records the compliance by the User in respect of [NAME]
Power Station/DC Converter Station [and, in the case of OTSDUW Arrangements, OTSUA] with the Grid
Code and the requirements of the Bilateral Agreement and Construction Agreement dated [ ] with
reference number [ ]. It is completed by the Power Station/DC Converter Station owner in the case of
Plant and/or Apparatus (including OTSUA) connected to the National Electricity Transmission System
and for Embedded Plant.
We have recorded our compliance against each requirement of the Grid Code which applies to the Power
Station/DC Converter Station/OTSUA, together with references to supporting evidence and a commentary
where this is appropriate, and have provided this to NGET. A copy of the Compliance Statement is
attached.
Supporting evidence, in the form of simulation results, test results, manufacturer’s data and other
documentation, is attached in the User Data File Structure.
The User hereby certifies that, to the best of its knowledge and acting in accordance with Good Industry
Practice, [the Power Station is compliant with the Grid Code and the Bilateral Agreement] [the OTSUA is
compliant with the Grid Code and the Construction Agreement] in all aspects [with the following
Unresolved Issues*] [with the following derogation(s)**]:
Connection
Condition
Compliance
certified by:
Requirement
Ref:
Issue
Title:
[PERSON DESIGNATION]
Of
[USER DETAILS]
Name:
[PERSON]
Signature:
[PERSON]
Date:
* Include for Interim User Self Certification of Compliance ahead of Interim Operational Notification.
** Include for final User Self Certification of Compliance ahead of Final Operational Notification where derogation(s) have been granted.
If no derogation(s) required delete wording and Table.
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APPENDIX 3 - SIMULATION STUDIES
CP.A.3.1.1
This Appendix sets out the simulation studies required to be submitted to NGET to
demonstrate compliance with the Connection Conditions unless otherwise agreed with
NGET. This Appendix should be read in conjunction with CP.6 with regard to the submission
of the reports to NGET. Where there is any inconsistency in the technical requirements in
respect of which compliance is being demonstrated by simulation in this Appendix and
CC.6.3 and the Bilateral Agreement, the provisions of the Bilateral Agreement and CC.6.3
prevail. The studies specified in this Appendix will normally be sufficient to demonstrate
compliance. However NGET may agree an alternative set of studies proposed by the
Generator or DC Converter Station owner provided NGET deem the alternative set of
studies sufficient to demonstrate compliance with the Grid Code and the Bilateral
Agreement.
CP.A.3.1.2
The Generator or DC Converter Station owner shall submit simulation studies in the form
of a report to demonstrate compliance. In all cases the simulation studies must utilise models
applicable to the Generating Unit, DC Converter or Power Park Module with proposed or
actual parameter settings. Reports should be submitted in English with all diagrams and
graphs plotted clearly with legible axes and scaling provided to ensure any variations in
plotted values is clear.
CP.A.3.1.3
In the case of an Offshore Power Station where OTSDUW Arrangements apply simulation
studies by the Generator should include the action of any relevant OTSUA where applicable
to demonstrate compliance with the Grid Code and the Bilateral Agreement at the
Interface Point.
CP.A.3.2
Power System Stabiliser Tuning
CP.A.3.2.1
In the case of a Synchronous Generating Unit the Power System Stabiliser tuning
simulation study report required by CC.A.6.2.5.6 or required by the Bilateral Agreement
shall contain:
(i)
the Excitation System model including the Power System Stabiliser with settings as
required under the Planning Code (PC.A.5.3.2(c))
(ii)
on load time series dynamic simulation studies of the response of the Excitation
System with and without the Power System Stabiliser to 2% and 10% steps in the
reference voltage and a three phase short circuit fault applied to the higher voltage side
of the Generating Unit transformer for 100ms. The simulation studies should be carried
out with the Generating Unit operating at full Active Power and maximum leading
Reactive Power import with the fault level at the Supergrid HV connection point at
minimum or as otherwise agreed with NGET. The results should show Generating Unit
field voltage, Generating Unit terminal voltage, Power System Stabiliser output,
Generating Unit Active Power and Generating Unit Reactive Power output.
(iii) gain and phase Bode diagrams for the open loop frequency domain response of the
Generating Unit Excitation System with and without the Power System Stabiliser.
These should be in a suitable format to allow assessment of the phase contribution of
the Power System Stabiliser and the gain and phase margin of the Excitation
System with and without the Power System Stabiliser in service.
(iv) an eigenvalue plot to demonstrate that all modes remain stable when the Power
System Stabiliser gain is increased by at least a factor of 3 from the designed
operating value.
(v) gain Bode diagram for the closed loop on load frequency domain response of the
Generating Unit Excitation System with and without the Power System Stabiliser.
The Generating Unit operating at full load and at unity power factor. These diagrams
should be in a suitable format to allow comparison of the Active Power damping across
the frequency range specified in CC.A.6.2.6.3 with and without the Power System
Stabiliser in service.
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CP.A.3.2.2
In the case of Onshore Non-Synchronous Generating Units, Onshore DC Converters
and Onshore Power Park Modules and OTSDUW Plant and Apparatus at the Interface
Point the Power System Stabiliser tuning simulation study report required by CC.A.7.2.4.1
or required by the Bilateral Agreement shall contain:
(i)
the Voltage Control System model including the Power System Stabiliser with
settings as required under the Planning Code (PC.A.5.4) and Bilateral Agreement.
(ii)
on load time series dynamic simulation studies of the response of the Voltage Control
System with and without the Power System Stabiliser to 2% and 10% steps in the
reference voltage and a three phase short circuit fault applied to the Grid Entry Point
or the Interface Point in the case of OTSDUW Plant and Apparatus for 100ms. The
simulation studies should be carried out operating at full Active Power and maximum
leading Reactive Power import condition with the fault level at the Supergrid HV
connection point at minimum or as otherwise agreed with NGET. The results should
show appropriate signals to demonstrate the expected damping performance of the
Power System Stabiliser.
(iii) any other simulation as specified in the Bilateral Agreement or agreed between the
Generator or DC Converter Owner or Offshore Transmission Licensee and NGET.
CP.A.3.3
Reactive Capability across the Voltage Range
CP.A.3.3.1
The Generator or DC Converter station owner shall supply simulation studies to
demonstrate the capability to meet CC.6.3.4 by submission of a report containing:
(i)
a load flow simulation study result to demonstrate the maximum lagging Reactive
Power capability of the Synchronous Generating Unit, DC Converter, OTSUA or
Power Park Module at Rated MW when the Grid Entry Point or User System Entry
Point if Embedded or Interface Point (in case of OTSUA) voltage is at 105% of
nominal.
(ii)
a load flow simulation study result to demonstrate the maximum leading Reactive
Power capability of the Synchronous Generating Unit, DC Converter, OTSUA or
Power Park Module at Rated MW when the Grid Entry Point or User System Entry
Point if Embedded or Interface Point (in case of OTSUA) voltage is at 95% of
nominal.
CP.A.3.3.2
In the case of a Synchronous Generating Unit the terminal voltage in the simulation should
be the nominal voltage for the machine. Where necessary to demonstrate compliance with
CC.6.3.4 and subject to compliance with CC.6.3.8 (a) (v), the Generator shall repeat the two
simulation studies with the terminal voltage being greater than the nominal voltage and less
than or equal to the maximum terminal voltage. The two additional simulations do not need
to have the same terminal voltage.
CP.A.3.3.3
In the case of a Synchronous Generating Unit the Generator shall supply two sets of
simulation studies to demonstrate the capability to meet the operational requirements of
BC2.A.2.6 and CC.6.1.7 at the minimum and maximum short circuit levels when changing
tap position. Each set of simulation studies shall be at the same system conditions. None of
the simulation studies shall include the Synchronous Generating Unit operating at the
limits of its Reactive Power output.
The simulation results shall include the Reactive Power output of the Synchronous
Generating Unit and the voltage at the Grid Entry Point or, if Embedded, the User
System Entry Point with the Generating Unit transformer at two adjacent tap positions with
the greatest interval between them and the terminal voltage of the Synchronous
Generating Unit equal to
its nominal value; and
subject to compliance with CC.6.3.8 (a) (v), its maximum value.
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CP.A.3.3.4
In the case of a Power Park Module where the load flow simulation studies show that the
individual Power Park Units deviate from nominal voltage to meet the Reactive Power
requirements then evidence must be provided from factory (e.g. in a Manufacturer’s Data &
Performance Report) or site testing that the Power Park Unit is capable of operating
continuously at the operating points determined in the load flow simulation studies.
CP.A.3.4
Voltage Control and Reactive Power Stability
CP.A.3.4.1
In the case of a power station containing Power Park Modules and/or OTSUA the
Generator shall provide a report to demonstrate the dynamic capability and control stability
of the Power Park Module. The report shall contain:
(i)
a dynamic time series simulation study result of a sufficiently large negative step in
System voltage to cause a change in Reactive Power from zero to the maximum
lagging value at Rated MW.
(ii)
a dynamic time series simulation study result of a sufficiently large positive step in
System voltage to cause a change in Reactive Power from zero to the maximum
leading value at Rated MW.
(iii) a dynamic time series simulation study result to demonstrate control stability at the
lagging Reactive Power limit by application of a -2% voltage step while operating within
5% of the lagging Reactive Power limit.
(iv) a dynamic time series simulation study result to demonstrate control stability at the
leading Reactive Power limit by application of a +2% voltage step while operating
within 5% of the leading Reactive Power limit.
CP.A.3.4.2
All the above studies should be completed with a nominal network voltage for zero Reactive
Power transfer at the Grid Entry Point or User System Entry Point if Embedded or, in the
case of OTSUA, Interface Point unless stated otherwise and the fault level at the HV
connection point at minimum as agreed with NGET.
CP.A.3.4.3
NGET may permit relaxation from the requirements of CP.A.3.4.1(i) and (ii) for voltage
control if the Power Park Modules are comprised of Power Park Units in respect of which
the User has in its submissions to NGET referenced an appropriate Manufacturer’s Data &
Performance Report which is acceptable to NGET for voltage control.
CP.A.3.4.4
In addition NGET may permit a further relaxation from the requirements of CP.A.3.4.1(iii) and
(iv) if the User has in its submissions to NGET referenced an appropriate Manufacturer’s
Data & Performance Report for a Power Park Module mathematical model for voltage
control acceptable to NGET.
CP.A.3.5
Fault Ride Through
CP.A.3.5.1
The Generator, (including where undertaking OTSDUW) or DC Converter Station owner
shall supply time series simulation study results to demonstrate the capability of NonSynchronous Generating Units, DC Converters, Power Park Modules and OTSUA to
meet CC.6.3.15 by submission of a report containing:
(i)
a time series simulation study of a 140ms solid three phase short circuit fault applied on
the nearest point of the National Electricity Transmission System operating at
Supergrid voltage to the Non-Synchronous Generating Unit, DC Converter, Power
Park Module or OTSUA.
(ii)
time series simulation study of 140ms unbalanced short circuit faults applied on the
nearest point of the National Electricity Transmission System operating at
Supergrid voltage to the Non-Synchronous Generating Unit, DC Converter, Power
Park Module or OTSUA. The unbalanced faults to be simulated are:
1. a phase to phase fault
2. a two phase to earth fault
3. a single phase to earth fault.
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For a Non-Synchronous Generating Unit, DC Converter, Power Park Module or OTSUA
the simulation study should be completed with the Non-Synchronous Generating Unit, DC
Converter, Power Park Module or OTSUA operating at full Active Power and maximum
leading Reactive Power import and the fault level at the Supergrid HV connection point at
minimum or as otherwise agreed with NGET.
(iii) time series simulation studies of balanced Supergrid voltage dips applied on the
nearest point of the National Electricity Transmission System operating at
Supergrid voltage to the Non-Synchronous Generating Unit, DC Converter, Power
Park Module or OTSUA. The simulation studies should include:
1. 30% retained voltage lasting 0.384 seconds
2. 50% retained voltage lasting 0.71 seconds
3. 80% retained voltage lasting 2.5 seconds
4. 85% retained voltage lasting 180 seconds.
For a Non-Synchronous Generating Unit, DC Converter, Power Park Module or OTSUA
the simulation study should be completed with the Non-Synchronous Generating Unit, DC
Converter, Power Park Module or OTSUA operating at full Active Power and zero
Reactive Power output and the fault level at the Supergrid HV connection point at minimum
or as otherwise agreed with NGET. Where the Non-Synchronous Generating Unit, DC
Converter or Power Park Module is Embedded the minimum Network Operator’s
System impedance to the Supergrid HV connection point shall be used which may be
calculated from the maximum fault level at the User System Entry Point.
For DC Converters the simulations should include the duration of each voltage dip 1 to 4
above for which the DC Converter will remain connected.
CP.A.3.5.2
In the case of Power Park Modules comprised of Power Park Units in respect of which the
User’s reference to a Manufacturer’s Data & Performance Report has been accepted by
NGET for Fault Ride Through, CP.A.3.5.1 will not apply provided:
(i)
the Generator or DC Converter Station owner demonstrates by load flow simulation
study result that the faults and voltage dips at either side of the Power Park Unit
transformer corresponding to the required faults and voltage dips in CP.A.3.5.1 applied
at the nearest point of the National Electricity Transmission System operating at
Supergrid voltage are less than those included in the Manufacturer’s Data &
Performance Report,
or;
(ii)
the same or greater percentage faults and voltage dips in CP.A.3.5.1 have been applied
at either side of the Power Park Unit transformer in the Manufacturer’s Data &
Performance Report.
CP.A.3.5.3
In the case of an Offshore Power Park Module or Offshore DC Converter the studies may
instead be completed at the LV Side of the Offshore Platform. For fault simulation studies
described in CCA.8.5.1(i) and CCA.8.5.1(ii) a retained voltage of 15% or lower may be
applied at the LV Side of the Offshore Platform on the faulted phases. For voltage dip
simulation studies described in CP.A.3.5.1(iii) the same voltage levels and durations as
normally applied at the National Electricity Transmission System operating at Supergrid
Voltage will be applied at the LV Side of the Offshore Platform.
CP.A.3.6
Load Rejection
CP.A.3.6.1
In respect of Generating Units or DC Converters or Power Park Modules with a
Completion Date on or after 1 January 2012, the Generator or DC Converter Station
owner shall demonstrate the speed control performance of the plant under a part load
rejection condition as required by CC.6.3.7(c)(i), through simulation study. In respect of
Generating Units or DC Converters or Power Park Modules, including those with a
Completion Date before 1 January 2013, the load rejection capability while still supplying
load must be stated in accordance with PC.A.5.3.2(f).
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CP.A.3.6.2
For Power Park Modules comprised of Power Park Units having a corresponding
generically verified and validated model included in the Manufacturer’s Data &
Performance Report this study is not required if the correct Manufacturer’s Data &
Performance Report reference has been submitted in the appropriate location in the Data
Registration Code.
CP.A.3.6.3
The simulation study should comprise of a Generating Unit, DC Converter or Power Park
Module connected to the total System with a local load shown as “X” in figure CP.A.3.6.1.
The load “X” is in addition to any auxiliary load of the Power Station connected directly to
the Generating Unit, DC Converter or Power Park Module and represents a small portion
of the System to which the Generating Unit, DC Converter or Power Park Module is
attached. The value of “X” should be the minimum for which the Generating Unit, DC
Converter or Power Park Module can control the power island frequency to less than 52Hz.
Where transient excursions above 52Hz occur the Generator or DC Converter Owner
should ensure that the duration above 52Hz is less than any high frequency protection
system applied to the Generating Unit, DC Converter or Power Park Module.
CP.A.3.6.4
At the start of the simulation study the Generating Unit, DC Converter or Power Park
Module will be operating maximum Active Power output. The Generating Unit, DC
Converter or Power Park Module will then be islanded from the Total System but still
supplying load “X” by the opening of a breaker, which is not the Generating Unit, DC
Converter or Power Park Module connection circuit breaker (the governor should therefore,
not receive any signals that the breaker has opened other than the reduction in load and
subsequent increase in speed). A schematic arrangement of the simulation study is
illustrated by Figure CP.A.3.6.1.
Figure CP.A.3.6.1 – Diagram of Load Rejection Study
CP.A.3.6.5
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Simulation study shall be performed for both control modes, Frequency Sensitive Mode
(FSM) and Limited Frequency Sensitive Mode (LFSM). The simulation study results
should indicate Active Power and Frequency in the island system that includes the
Generating Unit, DC Converter or Power Park Module.
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CP.A.3.6.6
To allow validation of the model used to simulate load rejection in accordance with
CC.6.3.7(c)(i) as described a further simulation study is required to represent the largest
positive Frequency injection step or fast ramp (BC1 and BC3 of Figure 2) that will be applied
as a test as described in OC5.A.2.8 and OC5.A.3.6.
CP.A.3.7
Voltage and Frequency Controller Model Verification and Validation
CP.A.3.7.1
For Generating Units, DC Converters or Power Park Modules with a Completion Date
after 1 January 2012 or subject to a Modification to a Excitation System, voltage control
system, governor control system or Frequency control system after 1 January 2012 the
Generator or DC Converter Station owner shall provide simulation studies to verify that the
proposed controller models supplied to NGET under the Planning Code are fit for purpose.
These simulation study results shall be provided in the timescales stated in the Planning
Code. For Power Park Modules comprised of Power Park Units having a corresponding
generically verified and validated model in a Manufacturer’s Data & Performance Report
NGET may permit the simulation studies detailed in CP.A.3.7.2, CP.A.3.7.4 and CP.A.3.7.5
to be replaced by submission of the correct Manufacturer’s Data & Performance Report
reference in the appropriate location in the Data Registration Code.
CP.A.3.7.2
To demonstrate the Frequency control or governor/load controller/plant model the
Generator or DC Converter Station owner shall submit a simulation study representing the
response of the Synchronous Generating Unit, DC Converter or Power Park Module
operating at 80% of Registered Capacity. The simulation study event shall be equivalent to:
(i)
a ramped reduction in the measured System Frequency of 0.5Hz in 10 seconds
followed by
(ii)
20 seconds of steady state with the measured System Frequency depressed by 0.5Hz
followed by
(iii) a ramped increase in measured System Frequency of 0.3Hz over 30 seconds followed
by
(iv) 60 seconds of steady state with the measured System Frequency depressed by 0.2Hz
as illustrated in Figure CP.A.3.7.2 below.
Figure CP.A.3.7.2
The simulation study shall show Active Power output (MW) and the equivalent of
Frequency injected.
CP.A.3.7.3
To demonstrate the Excitation System model the Generator shall submit simulation studies
representing the response of the Synchronous Generating Unit as follows:
(i)
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operating open circuit at rated terminal voltage and subjected to a 2% step increase in
terminal voltage reference.
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(ii)
operating at Rated MW, nominal terminal voltage and unity power factor subjected to a
2% step increase in the voltage reference. Where a Power System Stabiliser is
included within the Excitation System this shall be in service.
The simulation study shall show the terminal voltage, field voltage of the Generating Unit,
Active Power, Reactive Power and Power System Stabiliser output signal as appropriate.
CP.A.3.7.4
To demonstrate the Voltage Controller model the Generator or DC Converter Station
owner shall submit a simulation study representing the response of the Non-Synchronous
Generating Unit, DC Converter or Power Park Module operating at Rated MW and unity
power factor at the connection point to a 2% step increase in the voltage reference. The
simulation study shall show the terminal voltage, Active Power, Reactive Power and
Power System Stabiliser output signal as appropriate.
CP.A.3.7.5
To validate that the excitation and voltage control models submitted under the Planning
Code are a reasonable representation of the dynamic behaviour of the Synchronous
Generating Unit, DC Converter Station or Power Park Module as built, the Generator or
DC Converter Station owner shall repeat the simulation studies outlined above but using
the operating conditions of the equivalent tests. The simulation study results shall be
displayed overlaid on the actual test results.
CP.A.3.7.7
For Generating Units or DC Converters with a Completion Date after 1 January 2012 or
subject to a Modification to the governor system or Frequency control system after 1
January 2013 to validate that the governor/load controller/plant or Frequency control models
submitted under the Planning Code is a reasonable representation of the dynamic
behaviour of the Synchronous Generating Unit or DC Converter Station as built, the
Generator or DC Converter Station owner shall repeat the simulation studies outlined
above but using the operating conditions of the equivalent tests. The simulation study results
shall be displayed overlaid on the actual test results.
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CP.A.3.8
Sub-synchronous Resonance Control and Power Oscillation Damping Control for DC
Converters
CP.A.3.8.1
To demonstrate the compliance of the sub-synchronous control function with CC.6.3.16(a)
and the terms of the Bilateral Agreement, the DC Converter Station owner or Generator
undertaking OTSDUW shall submit a simulation study report.
CP.A.3.8.2
Where power oscillation damping control function is specified on a DC Converter the DC
Converter Station owner or Generator undertaking OTSDUW shall submit a simulation
study report to demonstrate the compliance with CC.6.3.16(b) and the terms of the Bilateral
Agreement.
CP.A.3.8.3
The simulation studies should utilise the DC Converter control system models including the
settings as required under the Planning Code (PC.A.5.3.2). The network conditions for the
above simulation studies should be discussed with NGET prior to commencing any
simulation studies.
< END OF COMPLIANCE PROCESSES >
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OPERATING CODE NO. 1
(OC1)
DEMAND FORECASTS
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
OC1.1 INTRODUCTION...................................................................................................................................2
OC1.2 OBJECTIVE ..........................................................................................................................................2
OC1.3 SCOPE..................................................................................................................................................2
OC1.4 DATA REQUIRED BY NGET IN THE OPERATIONAL PLANNING PHASE .......................................2
OC1.5 DATA REQUIRED BY NGET IN THE PROGRAMMING PHASE, CONTROL PHASE AND
POST-CONTROL PHASE..................................................................................................................................3
OC1.6 NGET FORECASTS .............................................................................................................................5
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OC1.1
INTRODUCTION
OC1.1.1
Operating Code No.1 ("OC1") is concerned with Demand forecasting for operational
purposes. In order to match generation output with Demand for electricity it is necessary to
undertake Demand forecasting. It is also necessary to undertake Demand forecasting of
Reactive Power.
OC1.1.2
In the Operational Planning Phase, Demand forecasting shall be conducted by NGET
taking account of Demand forecasts furnished by Network Operators, who shall provide
NGET with information in the form set out in this OC1. The data supplied under the PC is
also taken into account.
OC1.1.3
In the Programming Phase and Control Phase, NGET will conduct its own Demand
forecasting taking into account information to be furnished by Suppliers and Network
Operators and the other factors referred to in OC1.6.1.
OC1.1.4
In this OC1, the point of connection of the External Interconnection to the National
Electricity Transmission System shall be considered as a Grid Supply Point. Reactive
Power Demand includes the series Reactive losses of the User's System but excludes any
network susceptance and any Reactive compensation on the User's System. NGET will
obtain the lumped network susceptance and details of Reactive compensation from the
requirements to submit data under the PC.
OC1.1.5
Data relating to Demand Control should include details relating to MW.
OC1.1.6
OC1 deals with the provision of data on Demand Control in the Operational Planning
Phase, the Programming Phase and the Post-Control Phase, whereas OC6 (amongst
other things) deals with the provision of data on Demand Control following the
Programming Phase and in the Control Phase.
OC1.1.7
In this OC1, Year 0 means the current Financial Year at any time, Year 1 means the next
Financial Year at any time, Year 2 means the Financial Year after Year 1, etc.
OC1.1.8
References in OC1 to data being supplied on a half hourly basis refer to it being supplied for
each period of 30 minutes ending on the hour and half-hour in each hour.
OC1.2
OBJECTIVE
The objectives of OC1 are to:
OC1.2.1
enable the provision of data to NGET by Users in the Programming Phase, Control Phase
and Post-Control Phase; and
OC1.2.2
provide for the factors to be taken into account by NGET when Demand forecasting in the
Programming Phase and Control Phase.
OC1.3
SCOPE
OC1 applies to NGET and to Users which in this OC1 means:
(a) Network Operators, and
(b) Suppliers.
OC1.4
DATA REQUIRED BY NGET IN THE OPERATIONAL PLANNING PHASE
OC1.4.1
(a) Each User, as specified in (b) below, shall provide NGET with the data requested in
OC1.4.2 below.
(b) The data will need to be supplied by each Network Operator directly connected to the
National Electricity Transmission System in relation to Demand Control and in
relation each Generator with respect to the output of Embedded Medium Power
Stations within its System.
OC1.4.2
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(a) Data
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By calendar week 28 each year each Network Operator will provide to NGET in writing
the forecast information listed in (c) below for the current Financial Year and each of
the succeeding five Financial Years.
(b) Data Providers
In circumstances when the busbar arrangement at a Grid Supply Point is expected to
be operated in separate sections, separate sets of forecast information for each section
will be provided to NGET.
(c) Embedded Medium Power Station Output and Demand Control
For the specified time of the annual peak half hour National Electricity Transmission
System Demand, as specified by NGET under PC.A.5.2.2, the output of Embedded
Medium Power Stations and forecasts of Demand to be relieved by Demand Control
on a Grid Supply Point basis giving details of the amount and duration of the Demand
Control.
OC1.5
DATA REQUIRED BY NGET IN THE PROGRAMMING PHASE, CONTROL PHASE AND
POST-CONTROL PHASE
OC1.5.1
Programming Phase
For the period of 2 to 8 weeks ahead the following will be supplied to NGET in writing by
1000 hours each Monday:
(a) Demand Control
Each Network Operator will supply MW profiles of the amount and duration of their
proposed use of Demand Control which may result in a Demand change equal to or
greater than the Demand Control Notification Level (averaged over any half hour on
any Grid Supply Point) on a half hourly and Grid Supply Point basis;
(b) Medium Power Station Operation
Each Network Operator will, if reasonably required by NGET, supply MW schedules for
the operation of Embedded Medium Power Stations within its System on a half hourly
and Grid Supply Point basis.
OC1.5.2
For the period 2 to 12 days ahead the following will be supplied to NGET in writing by 1200
hours each Wednesday:
(a) Demand Control
Each Network Operator will supply MW profiles of the amount and duration of their
proposed use of Demand Control which may result in a Demand change equal to or
greater than the Demand Control Notification Level (averaged over any half hour on
any Grid Supply Point) on a half hourly and Grid Supply Point basis;
(b) Medium Power Station Operation
Each Network Operator will, if reasonably required by NGET, supply MW schedules for
the operation of Embedded Medium Power Stations within its System on a half hourly
and Grid Supply Point basis.
OC1.5.3
Medium Power Station Output
Each Network Operator will, if reasonably required by NGET, supply NGET with MW
schedules for the operation of Embedded Medium Power Stations within its System on a
half hourly and Grid Supply Point basis in writing by 1000 hours each day (or such other
time specified by NGET from time to time) for the next day (except that it will be for the next
3 days on Fridays and 2 days on Saturdays and may be longer (as specified by NGET at
least one week in advance) to cover holiday periods);
OC1.5.4
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Other Codes
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Under OC6 each Network Operator will notify NGET of their proposed use of Demand
Control (which may result in a Demand change equal to or greater than the Demand
Control Notification Level), and under BC1, each Supplier will notify NGET of their
proposed use of Customer Demand Management (which may result in a Demand change
equal to or greater than the Customer Demand Management Notification Level) in this
timescale.
OC1.5.5
Control Phase
OC1.5.5.1
Demand Control
Under OC6, each Network Operator will notify NGET of any Demand Control proposed by
itself which may result in a Demand change equal to or greater than the Demand Control
Notification Level averaged over any half hour on any Grid Supply Point which is planned
after 1000 hours, and of any changes to the planned Demand Control notified to NGET
prior to 1000 hours as soon as possible after the formulation of the new plans;
OC1.5.5.2
Customer Demand Management
(a) Each Supplier will notify NGET of any Customer Demand Management proposed by
itself which may result in a Demand change equal to or greater than the Customer
Demand Management Notification Level averaged over any half hour on any Grid
Supply Point which is planned to occur at any time in the Control Phase and of any
changes to the planned Customer Demand Management already notified to NGET as
soon as possible after the formulation of the new plans.
(b) The following information is required on a Grid Supply Point and half-hourly basis:
OC1.5.5.3
(i)
the proposed date, time and duration of implementation of Customer Demand
Management; and
(ii)
the proposed reduction in Demand by use of Customer Demand Management.
Load Management Blocks
In Scotland, by 11:00 each day, each Supplier who controls a Load Management Block of
Demand with a capacity of 5MW or more shall submit to NGET a schedule of its proposed
switching times and profiles in respect of each block for the next day.
OC1.5.6
Post-Control Phase
The following will be supplied to NGET in writing by 0600 hours each day in respect of
Active Power data and by 1000 hours each day in respect of Reactive Power data:
(a) Demand Control
Each Network Operator will supply MW profiles for the previous calendar day of the
amount and duration of Demand reduction achieved by itself from the use of Demand
Control equal to or greater than the Demand Control Notification Level (averaged
over any half hour on any Grid Supply Point), on a half hourly and Grid Supply Point
basis.
(b) Customer Demand Management
Each Supplier will supply MW profiles of the amount and duration of Demand reduction
achieved by itself from the use of Customer Demand Management equal to or greater
than the Customer Demand Management Notification Level (averaged over any half
hour on any Grid Supply Point) on a half hourly and Grid Supply Point basis during
the previous calendar day.
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OC1.6
NGET FORECASTS
OC1.6.1
The following factors will be taken into account by NGET when conducting National
Electricity Transmission System Demand forecasting in the Programming Phase and
Control Phase:
(a) Historic Demand data (this includes National Electricity Transmission System
Losses).
(b) Weather forecasts and the current and historic weather conditions.
(c) The incidence of major events or activities which are known to NGET in advance.
(d) Anticipated interconnection flows across External Interconnections.
(e) Demand Control equal to or greater than the Demand Control Notification Level
(averaged over any half hour at any Grid Supply Point) proposed to be exercised by
Network Operators and of which NGET has been informed.
(f)
Customer Demand Management equal to or greater than the Customer Demand
Management Notification Level (averaged over any half hour at any Grid Supply
point) proposed to be exercised by Suppliers and of which NGET has been informed.
(g) Other information supplied by Users.
(h) Anticipated Pumped Storage Unit demand.
(i)
the sensitivity of Demand to anticipated market prices for electricity.
(j)
BM Unit Data submitted by BM Participants to NGET in accordance with the
provisions of BC1 and BC2.
(k) Demand taken by Station Transformers
OC1.6.2
Taking into account the factors specified in OC1.6.1 NGET uses Demand forecast
methodology to produce forecasts of National Electricity Transmission System Demand.
A written record of the use of the methodology must be kept by NGET for a period of at least
12 months.
OC1.6.3
The methodology will be based upon factors (a), (b) and (c) above to produce, by statistical
means, unbiased forecasts of National Demand. National Electricity Transmission
System Demand will be calculated from these forecasts but will also take into account
factors (d), (e), (f), (g), (h), (i) and (j) above. No other factors are taken into account by
NGET, and it will base its National Electricity Transmission System Demand forecasts on
those factors only.
< END OF OPERATING CODE NO. 1 >
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OPERATING CODE NO. 2
(OC2)
OPERATIONAL PLANNING AND DATA PROVISION
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
OC2.1 INTRODUCTION................................................................................................................................... 1
OC2.2 OBJECTIVE .......................................................................................................................................... 2
OC2.3 SCOPE .................................................................................................................................................. 2
OC2.4 PROCEDURE ....................................................................................................................................... 3
OC2.4.1 Co-ordination of outages ............................................................................................................ 3
OC2.4.2 Data Requirements .................................................................................................................. 17
OC2.4.3 Negative Reserve Active Power Margins ................................................................................. 19
OC2.4.4 Frequency Sensitive Operation ................................................................................................ 22
OC2.4.6 Operating Margin Data Requirements ..................................................................................... 22
APPENDIX 1 - PERFORMANCE CHARTS ..................................................................................................... 25
APPENDIX 2 - GENERATION PLANNING PARAMETERS ............................................................................ 27
APPENDIX 3 - CCGT MODULE PLANNING MATRIX .................................................................................... 29
APPENDIX 4 - POWER PARK MODULE PLANNING MATRIX ...................................................................... 30
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OC2.1
INTRODUCTION
OC2.1.1
Operating Code No. 2 ("OC2") is concerned with:
(a) the co-ordination of the release of Synchronous Generating Units and Power Park
Modules, External Interconnections, the National Electricity Transmission System
and Network Operators' Systems for construction, repair and maintenance;
(b) provision by NGET of the Surpluses both for the National Electricity Transmission
System and System Zones;
(c) the provision by Generators of Generation Planning Parameters for Gensets,
including CCGT Module Planning Matrices and Power Park Module Planning
Matrices, to NGET for planning purposes only; and
(d) the agreement for release of Existing Gas Cooled Reactor Plant for outages in certain
circumstances.
OC2.1.2
(a) Operational Planning involves planning, through various timescales, the matching of
generation output with forecast National Electricity Transmission System Demand
together with a reserve of generation to provide a margin, taking into account outages of
certain Generating Units, Power Park Modules, External Interconnections, and DC
Converters, and of parts of the National Electricity Transmission System and of
parts of Network Operators' Systems which is carried out to achieve, so far as
possible, the standards of security set out in NGET’s Transmission Licence, each
Relevant Transmission Licensee’s Transmission Licence or Electricity
Distribution Licence as the case may be.
(b) In general terms there is an "envelope of opportunity" for the release of Synchronous
Generating Units, Power Park Modules and External Interconnections, and for the
release of parts of the National Electricity Transmission System and parts of the
Network Operator’s User Systems for outages. The envelope is defined by the
difference between the total generation output expected from Large Power Stations,
Medium Power Stations and Demand, the operational planning margin and taking into
account External Interconnections.
OC2.1.3
In this OC2 for the purpose of Generator and Interconnector Owner outage co-ordination
Year 0 means the current calendar year at any time, Year 1 means the next calendar year at
any time, Year 2 means the calendar year after Year 1, etc. For the purpose of
Transmission outage planning Year 0 means the current Financial Year at any time, Year
1 means the next Financial Year at any time, Year 2 means the Financial Year after Year
1, etc. References to ‘weeks’ in OC2 are to calendar weeks as defined in ISO 8601.
OC2.1.4
References in OC2 to a Generator's and Interconnector Owner’s "best estimate" shall be
that Generator's or Interconnector Owner’s best estimate acting as a reasonable and
prudent Generator or Interconnector Owner in all the circumstances.
OC2.1.5
References to NGET planning the National Electricity Transmission System outage
programme on the basis of the Final Generation Outage Programme, are to NGET
planning against the Final Generation Outage Programme current at the time it so plans.
OC2.1.6
Where in OC2 data is required to be submitted or information is to be given on a particular
day, that data does not need to be submitted and that information does not need to be given
on that day if it is not a Business Day or it falls within a holiday period (the occurrence and
length of which shall be determined by NGET, in its reasonable discretion, and notified to
Users). Instead, that data shall be submitted and/or that information shall be given on such
other Business Day as NGET shall, in its reasonable discretion, determine. However,
NGET may determine that that data and/or information need not be submitted or given at all,
in which case it shall notify each User as appropriate.
OC2.1.7
In Scotland, it may be possible with the agreement of NGET to reduce the administrative
burden for Users in producing planning information where either the output or demand is
small.
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OC2.2
OBJECTIVE
OC2.2.1
(a) The objective of OC2 is to seek to enable NGET to harmonise outages of
Synchronous Generating Units, Power Park Modules and External
Interconnections in order that such outages are co-ordinated (taking account of
Embedded Medium Power Stations) between Generators and Network Operators,
and that such outages are co-ordinated taking into account National Electricity
Transmission System outages and other System outages, so far as possible to
minimise the number and effect of constraints on the National Electricity
Transmission System or any other System.
(b) In the case of Network Operator’ User Systems directly connected to the National
Electricity Transmission System this means in particular that there will also need to
be harmonisation of outages of Embedded Synchronous Generating Units and
Embedded Power Park Modules, and National Electricity Transmission System
outages, with Network Operators in respect of their outages on those Systems.
OC2.2.2
The objective of OC2 is also to enable the provision by NGET of the Surpluses both for the
National Electricity Transmission System and System Zones.
OC2.2.3
A further objective of OC2 is to provide for the agreement for outages for Existing Gas
Cooled Reactor Plant in certain circumstances and to enable a process to be followed in
order to provide for that.
OC2.2.4
The boundaries of the System Zones will be determined by NGET from time to time taking
into account the disposition of Generators' Power Stations and Interconnector Owners’
External Interconnections within the System Zones. The location of the boundaries will be
made available to all Users. Any User may request that NGET reviews any of the System
Zonal boundaries if that User considers that the current boundaries are not appropriate,
giving the reasons for their concerns. On receipt of such a request NGET will review the
boundaries if, in NGET's reasonable opinion, such a review is justified.
OC2.3
SCOPE
OC2.3.1
OC2 applies to NGET and to Users which in OC2 means:
(a) Generators, only in respect of their Large Power Stations or their Power Stations
which are directly connected to National Electricity Transmission System (and the
term Generator in this OC2 shall be construed accordingly);
(b) Network Operators; and
(c) Non-Embedded Customers; and
(d) DC Converter Station owners; and
(e) Interconnector Owners in respect of their External Interconnections.
OC2.3.2
NGET may provide to the Relevant Transmission Licensees any data which has been
submitted to NGET by any Users in respect of Relevant Units pursuant to the following
paragraphs of the OC2.
OC2.4.1.2.1 (a)
OC2.4.1.2.1 (e)
OC2.4.1.2.1 (j)
OC2.4.1.2.2 (a)
OC2.4.1.2.2 (i)
OC2.4.1.3.2 (a)
OC2.4.1.3.2 (b)
OC2.4.1.3.3
OC2.4.2.1 (a)
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OC2.3.3
For the purpose of OC2 only, the term Output Usable shall include the terms
Interconnector Export Capacity and Interconnector Import Capacity where the term
Output Usable is being applied to an External Interconnection.
OC2.4
PROCEDURE
OC2.4.1
Co-ordination of Outages
OC2.4.1.1
Under OC2 the interaction between NGET and Users will be as follows:
(a)
Each Generator, and each
Interconnector Owner and
NGET
In respect of outages of Synchronous Generating
Units, Power Park Modules and External
Interconnection Circuits and in respect of outages
of other Plant and/or Apparatus directly connected
to the National Electricity Transmission System;
(b)
NGET and each Generator
and each Inteconnector
Owner
in respect of National Electricity Transmission
System outages relevant to each Generator (other
than in respect of Embedded Small Power
Stations or Embedded Medium Power Stations)
and Interconnector Owner;
(c)
NGET and each Network
Operator
in respect of outages of all Embedded Large Power
Stations and in respect of outages of other Plant
and/or Apparatus relating to such Embedded
Large Power Stations;
(d)
NGET and each Network
Operator and each NonEmbedded Customer
in respect of National Electricity Transmission
System outages relevant to the particular Network
Operator or Non-Embedded Customers;
(e)
Each Network Operator and in respect of User System outages relevant to
each Non-Embedded
NGET; and
Customer and NGET
in respect of Network Operators only, outages of
the Network Operator’s User System that may
impact upon an Offshore Transmission System
connected to that Network Operator’s User
System.
OC2.4.1.2
Planning Of Synchronous Generating Unit And External Interconnection And Power Park
Module Outages
OC2.4.1.2.1
Operational Planning Phase - Planning for Calendar Years 3 to 5 inclusive – Weekly
Resolution
In each calendar year:
(a) By the end of week 2
Each Generator and each Interconnector Owner will provide NGET in writing with:
(i)
a provisional Synchronous Generating Unit and Power Park Module outage
programme (covering all non-Embedded Power Stations and Embedded Large
Power Stations) for Year 3 to Year 5 (inclusive) specifying the Synchronous
Generating Unit and/or Power Park Module and External Interconnection
Circuits and MW concerned, duration of proposed outages, the preferred date for
each outage and where there is a possibility of flexibility, the earliest start date and
latest finishing date; and
(ii)
a best estimate weekly Output Usable forecast of all its Gensets and External
Interconnections for Year 3 to Year 5.
(b) Between the end of week 2 and the end of week 12
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NGET will be:
(i)
calculating total winter peak generating capacity assumed to be available to the
Total System;
(ii)
calculating the total winter peak generating capacity expected from Large Power
Stations, taking into account Demand forecasts and details of proposed use of
Demand Control received under OC1, and an operational planning margin set by
NGET (the "Operational Planning Margin");
(iii) calculating the weekly peak generating capacity expected from Large Power
Stations taking into account demand forecasts and details of proposed use of
Demand Control received under OC1, and the Operational Planning Margin and
Zonal System Security Requirements. The total weekly peak MW needed to be
available is the "weekly total MW required".
The calculation under (iii) will effectively define the envelope of opportunity for outages
of Synchronous Generating Units and Power Park Modules.
During this period, NGET may, as appropriate, contact each Generator and each
Interconnector Owner who has supplied information to seek clarification on points.
(c) By the end of week 12
NGET will:
(i)
having taken into account the information notified to it by Generators and
Interconnector Owners and taking into account:
(1) National Electricity Transmission System constraints and outages,
(2) Network Operator System constraints and outages, known to NGET, and
(3) the Output Usable required, in its view, to meet weekly total MW
requirements,
provide each Generator and each Interconnector Owner in writing with any
suggested amendments to the provisional outage programme supplied by the
Generator and Interconnector Owner which NGET believes necessary, and will
advise Generators with Large Power Stations of the Surpluses both for the
National Electricity Transmission System and System Zones and potential
export limitations, on a weekly basis, which would occur without such
amendments;
(ii)
provide each Network Operator in writing with potential outages of Synchronous
Generating Units, External Interconnection Circuits and/or Power Park
Modules which may, in the reasonable opinion of NGET and the Network
Operator, affect the integrity of that Network Operator’s User System provided
that, in such circumstances NGET has notified the Generator concerned at least
48 hours beforehand of its intention to do so (including identifying the
Synchronous Generating Unit and/or Power Park Module concerned).
(d) By the end of week 14
(i)
Where a Generator or Interconnector Owner or a Network Operator is unhappy
with the suggested amendments to its provisional outage programme (in the case
of a Generator or Interconnector Owner) or such potential outages (in the case
of a Network Operator) it may contact NGET to explain its concerns and NGET
and that Generator or an Interconnector Owner or Network Operator will then
discuss the problem and seek to resolve it.
(ii)
The possible resolution of the problem may require NGET or a User to contact
other Generators and Network Operators, and joint meetings of all parties may, if
any User feels it would be helpful, be convened by NGET. The need for further
discussions, be they on the telephone or at meetings, can only be determined at
the time.
(e) By the end of week 25
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Each Generator will provide NGET in writing with an updated provisional Synchronous
Generating Unit and Power Park Module outage programme covering both
Embedded and non-Embedded Large Power Stations together with the best estimate
weekly Output Usable forecasts for each Genset, in all cases for Year 3 to Year 5
(inclusive). The updated provisional Synchronous Generating Unit and Power Park
Module outage programme will contain the MW concerned, duration of proposed
outages, the preferred date for each outage and, where applicable, earliest start date
and latest finishing date, together with an update of the Output Usable estimate
supplied under (a)(ii) above.
Each Interconnector Owner will provide NGET in writing with an updated provisional
External Interconnection Circuit outage programme together with best estimate
weekly Output Usable forecast for each External Interconnection, in all cases for
Year 3 to Year 5 (inclusive). The updated provisional External Interconnection Circuit
outage programme will contain the MW concerned, duration of proposed outages, the
preferred date for each outage and, where applicable, earliest start date and latest
finishing date, together with an update of the Output Usable estimate supplied under
(a)(ii) above.
(f)
Between the end of week 25 and the end of week 28
NGET will be considering the updated provisional Synchronous Generating Unit,
Power Park Module and External Interconnection Circuit outage programmes,
together with the best estimate weekly Output Usable forecasts supplied to it by
Generators and Interconnector Owners under (e) and their Registered Capacity and
will be analysing Operational Planning Margins for the period.
(g) By the end of week 28
NGET will:
(i)
provide each Generator and each Interconnector Owner in writing with details of
any suggested revisions considered by NGET as being necessary to the updated
provisional Synchronous Generating Unit, Power Park Module and External
Interconnection Circuit outage programmes supplied to NGET under (e) and will
advise Generators with Large Power Stations and Inteconnector Owners of the
Surpluses for the National Electricity Transmission System and System
Zones and potential export limitations on a weekly basis which would occur without
such revisions; and
(ii)
provide each Network Operator in writing with the update of potential outages of
Synchronous Generating Units, External Interconnection Circuits and/or
Power Park Modules which, in the reasonable opinion of NGET and the Network
Operator, affect the integrity of that Network Operator’s User System.
(h) By the end of week 31
Where a Generator, Interconnector Owner or a Network Operator is unhappy with
the revisions suggested to the updated provisional Synchronous Generating Unit,
Power Park Module and External Interconnector Circuit outage programme (in the
case of a Generator) or such update of potential outages (in the case of an
Interconnector Owner or Network Operator) under (g) it may contact NGET to
explain its concerns and the provisions set out in (d) above will apply to that process.
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(i)
By the end of week 42
NGET will:
(1) provide each Generator and each Interconnector Owner in writing with details of
suggested revisions considered by NGET as being necessary to the updated
provisional Synchronous Generating Unit, Power Park Module and External
Inteconnection Circuit outage programmes supplied to NGET and will advise
Generators with Large Power Stations and Interconnector Owners of the
Surpluses for the National Electricity Transmission System and System
Zones and potential export limitations, on a weekly basis which would occur
without such revisions;
(2) provide each Network Operator in writing with the update of potential outages of
Synchronous Generating Units and/or Power Park Modules which may, in the
reasonable opinion of NGET and the Network Operator, affect the integrity of that
Network Operator’s User System provided that, in such circumstances NGET
has notified the Generator or, as appropriate, the Interconnector Owner
concerned at least 48 hours beforehand of its intention to do so (including
identifying the Synchronous Generating Units and/or Power Park Modules
concerned).
(j)
By the end of week 45
NGET will seek to agree a Final Generation Outage Programme for Year 3 to Year 5.
If agreement cannot be reached on all aspects, NGET and each Generator and each
Interconnector Owner will record their agreement on as many aspects as have been
agreed and NGET will advise each Generator with Large Power Stations,
Interconnector Owner and each Network Operator, of the Surpluses for the
National Electricity Transmission System and System Zones on a weekly basis
which would occur in relation to those aspects not agreed. It is accepted that
agreement of the Final Generation Outage Programme is not a commitment on
Generators, Interconnector Owners or NGET to abide by it, but NGET will be
planning the National Electricity Transmission System outage programme on the
basis of the Final Generation Outage Programme and if in the event the Generator's
or the Interconnector Owner’s outages differ from those contained in the Final
Generation Outage Programme, or in any way conflict with the National Electricity
Transmission System outage programme, NGET need not alter the National
Electricity Transmission System outage programme.
OC2.4.1.2.2
Operational Planning Phase - Planning for Calendar Year 1 and Calendar Year 2 – Weekly
Resolution
The basis for Operational Planning for Year 1 and Year 2 will be the Final Generation
Outage Programmes agreed for Years 2 and 3:
In each calendar year:
(a) By the end of week 10
Each Generator and each Interconnector Owner will provide NGET in writing with its
previously agreed Final Generation Outage Programme updated and best estimate
weekly Output Usable forecasts for each Genset and for each External
Interconnection Circuit for weeks 1-52 of Years 1 and 2.
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(b) Between the end of week 10 and the end of week 12
NGET will be considering the updated proposed Synchronous Generating Unit,
Power Park Module and External Interconnection Circuit outage programme
together with the estimate of Output Usable supplied by Generators and
Interconnector Owners under (a) and will be analysing Operational Planning
Margins for the period. Taking these into account together with National Electricity
Transmission System constraints and outages and Network Operator User System
constraints and outages known to NGET, NGET will assess whether the estimates of
Output Usable supplied by Generators and Interconnector Owners are sufficient to
meet forecast National Electricity Transmission System Demand plus the
Operational Planning Margin.
(c) By the end of week 12
NGET will:
(i)
notify each Generator and each Interconnector Owner in writing whether the
Output Usable estimates are adequate for weeks 1-52 of Years 1 and 2, together
with suggested changes to its Final Generation Outage Programme where
necessary and will advise each Generator with Large Power Stations and each
Interconnector Owner of the Surpluses both for the National Electricity
Transmission System and System Zones and potential export limitations, on a
weekly resolution which would occur without such changes;
(ii)
provide each Network Operator in writing with weekly Output Usable estimates of
Generators and Interconnector Owners for weeks 1-52 of Years 1 and 2, and
updated details of potential outages of Synchronous Generating Units, Power
Park Modules and/or External Interconnection Circuits which may, in the
reasonable opinion of NGET and the Network Operator, affect the integrity of that
Network Operator’s User System provided that, in such circumstances, NGET
has notified the Generator or, as appropriate, the Interconnector Owner
concerned at least 48 hours beforehand of its intention to do so (including
identifying the affected Gensets or Synchronous Generating Units or Power
Park Modules and/or External Interconnection Circuits, as appropriate).
(d) By the end of week 14
Where a Generator, Interconnector Owner or a Network Operator is unhappy with
any suggested changes to its Final Generation Outage Programme (in the case of a
Generator) or such update of potential outages (in the case of an Interconnector
Owner or Network Operator), equivalent provisions to those set out in OC2.4.1.2.1(d)
will apply.
(e) By the end of week 34
Each Generator and each Interconnector Owner will provide NGET in writing with
revised best estimate weekly Output Usable forecasts for each Genset or External
Interconnection, as appropriate, for weeks 1-52 of Years 1 and 2.
(f)
Between the end of week 34 and the end of week 39
NGET will be analysing the revised estimates of Output Usable supplied by
Generators and Interconnector Owners under (e) and will be analysing Operational
Planning Margins for the period. Taking these into account together with National
Electricity Transmission System constraints and outages and Network Operator
User System constraints and outages known to NGET, NGET will assess whether the
estimates of Output Usable supplied by Generators and Interconnector Owners are
sufficient to meet forecast National Electricity Transmission System Demand plus
the Operational Planning Margin.
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(g) By the end of week 39
NGET will:
(i)
notify each Generator and each Interconnector Owner in writing whether it
accepts the Output Usable estimates for weeks 1-52 of Years 1 and 2, and of any
suggested changes to its Final Generation Outage Programme where necessary
and will advise Generators with Large Power Stations and Interconnector
Owners of the Surpluses both for the National Electricity Transmission System
and System Zones and potential export limitations on a weekly basis which would
occur without such changes;
(ii)
provide each Network Operator in writing with Output Usable estimates of
Generators and Interconnector Owners for weeks 1-52 of Years 1 and 2, and
updated details of potential outages of Synchronous Generating Units, Power
Park Modules and/or External Interconnection Circuits which may, in the
reasonable opinion of NGET and the Network Operator, affect the integrity of that
Network Operator’s User System provided that, in such circumstances, NGET
has notified the Generator or, as appropriate, Interconnector Owner concerned
at least 48 hours beforehand of its intention to do so (including identifying the
affected Gensets or Synchronous Generating Units or Power Park Modules
and/or External Interconnection as appropriate).
(h) By the end of week 46
Where a Generator, an Interconnector Owner or a Network Operator, is unhappy
with any suggested changes to its Final Generation Outage Programme (in the case
of a Generator) or such update of potential outages (in the case of an Interconnector
Owner or Network Operator), equivalent provisions to those set out in OC2.4.1.2.1(d)
will apply.
(i)
By the end of week 48
NGET will seek to agree the revised Final Generation Outage Programme for Year 1
and Year 2. If agreement cannot be reached on all aspects, NGET and each
Interconnector Owner and each Generator will record their agreement on as many
aspects as have been agreed and NGET will advise each Generator with Large Power
Stations, Interconnector Owner and each Network Operator, of Generating Plant
Demand Margins for national and zonal groups, on a weekly basis, which would occur
in relation to those aspects not agreed. It is accepted that agreement of the Final
Generation Outage Programme is not a commitment on Generators, Interconnector
Owners or NGET to abide by it, but NGET will be planning the National Electricity
Transmission System outage programme on the basis of the Final Generation
Outage Programme and if, in the event, a Generator's and/or Interconnector
Owner’s outages differ from those contained in the Final Generation Outage
Programme, or in any way conflict with the National Electricity Transmission
System outage programme, NGET need not alter the National Electricity
Transmission System outage programme.
OC2.4.1.2.3
Planning for Calendar Year 0 – Weekly Resolution
The basis for Operational Planning for Year 0 will be the revised Final Generation Outage
Programme agreed for Year 1:
In each week:
(a) By 1600 hours each Wednesday – Weekly Resolution
Each Generator and each Interconnector Owner will provide NGET in writing with an
update of the Final Generation Outage Programme and a best estimate weekly
Output Usable forecast for each of its Gensets or its External Interconnection
Circuits, as appropriate, from the 2nd week ahead to the 52nd week ahead.
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(b) Between 1600 hours Wednesday and 1600 hours Friday
NGET will be analysing the revised estimates of Output Usable supplied by
Generators and Interconnector Owners under (a) and will be analysing Operational
Planning Margins for the period.
Taking into account National Electricity
Transmission System constraints and outages and Network Operator User System
constraints and outages known to NGET, NGET will assess whether the estimates of
Output Usable supplied by Generators and Interconnector Owners are sufficient to
meet forecast National Electricity Transmission System Demand plus the
Operational Planning Margin.
(c) By 1600 hours each Friday
NGET will:
OC2.4.1.2.4
(i)
notify each Generator with Large Power Stations, Interconnector Owner and
Network Operator, in writing if it considers the Output Usable forecasts will give
Surpluses and potential export limitations both for the National Electricity
nd
Transmission System and System Zones from the 2 week ahead to the 52nd
week ahead;
(ii)
provide each Network Operator, in writing with weekly Output Usable estimates
of Gensets and External Interconnection from the 2nd week ahead to the 52nd
week ahead and updated outages of Synchronous Generating Units, Power
Park Modules and/or External Interconnection Circuits which may, in the
reasonable opinion of NGET and the Network Operator, affect the integrity of that
Network Operator’s User System and in such circumstances, NGET shall notify
the Generator and Interconnector Owner concerned within 48 hours of so
providing (including identifying the affected Gensets or Synchronous Generating
Units and/or Power Park Modules and/or External Interconnection Circuits, as
appropriate), from the 2nd week ahead to the 52nd week ahead.
Programming Phase – 2-49 Days Ahead – Daily Resolution
(a) By 1200 hours each Friday
NGET will notify in writing each Generator with Large Power Stations, Interconnector
Owner and Network Operator if it considers the Output Usable forecasts will give MW
shortfalls both nationally and for constrained groups for the period 2-7 weeks ahead.
(b) By 1100 hours each Business Day
Each Generator and each Interconnector Owner shall provide NGET in writing with
the best estimate of daily Output Usable for each Genset or each External
Interconnection Circuit as appropriate for the period from and including day 2 ahead
to day 14 ahead, including the forecast return to service date for any such Generating
Unit, Power Park Module or External Interconnection subject to Planned Outage or
breakdown.
(c) By 1100 hours each Wednesday
For the period 2 to 49 days ahead, every Wednesday by 11:00 hours, each Generator
and each Interconnector Owner shall provide NGET in writing best estimate daily
Output Usable forecasts for each Genset or External Interconnection, and changes
(start and finish dates) to Planned Outage or to the return to service times of each
Synchronous Generating Unit, Power Park Module and/or External
Interconnection Circuit which is subject to breakdown.
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(d) Between 1100 hours and 1600 hours each Business Day
NGET will be analysing the revised estimates of Output Usable supplied by
Generators and Interconnector Owners under (b) and will be analysing Operational
Planning Margins for the period 2-14 days ahead. Taking into account National
Electricity Transmission System constraints and outages and Network Operator
User System constraints and outages known to NGET, NGET will assess whether the
estimates of Output Usable are sufficient to meet forecast National Electricity
Transmission System Demand plus the Operational Planning Margin.
(e) By 1600 hours each Business Day
(i)
NGET will notify in writing each Generator with Large Power Stations, each
Interconnector Owner and each Network Operator, of the Surpluses both for
the National Electricity Transmission System and System Zones and potential
export limitations, for the period from and including day 2 ahead to day 14 ahead
which it considers the Output Usable forecasts will give. The time of 1600 hours
can only be met in respect of any Generator, Interconnector Owner or Network
Operator if all the information from all Generators and Interconnector Owners
was made available to NGET by 1100 hours and if a suitable electronic data
transmission facility is in place between NGET and the Generator, or the
Interconnector Owner or the Network Operator, as the case may be, and if it is
fully operational. In the event that any of these conditions is not met, or if it is
necessary to revert to a manual system for analysing the information supplied and
otherwise to be considered, NGET reserve the right to extend the timescale for
issue of the information required under this sub-paragraph to each, or the relevant,
Generator, Interconnector Owner and/or Network Operator (as the case may
be) provided that such information will in any event be issued by 1800 hours.
(ii)
NGET will provide each Network Operator, where it has an effect on that User, in
writing with Output Usable estimates of Gensets and External Interconnections
from and including day 2 ahead to day 14 ahead and updated outages of
Synchronous Generating Units, Power Park Modules and/or External
Interconnection Circuits which are either in its User System or which may, in the
reasonable opinion of NGET and the Network Operator, affect the integrity of that
Network Operator’s User System and in such circumstances, NGET shall notify
the Generator and Interconnector Owner concerned within 48 hours of so
providing (including identifying the affected Gensets or Synchronous Generating
Units or Power Park Modules and/or External Interconnection Circuits, as
appropriate), for the period from and including day 2 ahead to day 14 ahead.
OC2.4.1.3
Planning of National Electricity Transmission System Outages
OC2.4.1.3.1
Operational Planning Phase - Planning for Financial Years 2 to 5 inclusive ahead
NGET shall plan National Electricity Transmission System outages required in Years 2 to
5 inclusive required as a result of construction or refurbishment works. This contrasts with
the planning of National Electricity Transmission System outages required in Years 0 and
1 ahead, when NGET also takes into account National Electricity Transmission System
outages required as a result of maintenance.
Users should bear in mind that NGET will be planning the National Electricity
Transmission System outage programme on the basis of the previous year's Final
Generation Outage Programme and if in the event a Generator's, an Interconnector
Owner’s or Network Operator's outages differ from those contained in the Final
Generation Outage Programme, or in the case of Network Operators, those known to
NGET, or in any way conflict with the National Electricity Transmission System outage
programme, NGET need not alter the National Electricity Transmission System outage
programme.
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OC2.4.1.3.2
In each calendar year:
(a) By the end of week 8
Each Network Operator will notify NGET in writing of details of proposed outages in
Years 2-5 ahead in its User System which may affect the performance of the Total
System (which includes but is not limited to outages of User System Apparatus at
Grid Supply Points and outages which constrain the output of Synchronous
Generating Units and/or Power Park Modules Embedded within that User System).
Each Network Operator will notify NGET in writing of details of proposed outages in
Years 2-5 ahead in its User System which may affect the declared values of Maximum
Export Capacity and/or Maximum Import Capacity for each Interface Point within its
User System together with the Network Operator’s revised best estimate of the
Maximum Export Capacity and/or Maximum Import Capacity during such outages.
Network Operators will also notify NGET of any automatic and/or manual post fault
actions that it intends to utilise or plans to utilise during such outages.
(b) By the end of week 13
Each Generator will inform NGET in writing of proposed outages in Years 2 - 5 ahead
of Generator owned Apparatus (eg. busbar selectors) other than Synchronous
Generating Units, and/or Power Park Modules, at each Grid Entry Point.
NGET will provide to each Network Operator and to each Generator and each
Interconnector Owner a copy of the information given to NGET under paragraph (a)
above (other than the information given by that Network Operator). In relation to a
Network Operator, the data must only be used by that User in planning and operating
that Network Operator’s User System and must not be used for any other purpose or
passed on to, or used by, any other business of that User or to, or by, any person within
any other such business or elsewhere.
(c) By the end of week 28
NGET will provide each Network Operator in writing with details of proposed outages
in Years 2-5 ahead which may, in NGET's reasonable judgement, affect the
performance of that Network Operator’s User System.
(d) By the end of week 30
Where NGET or a Network Operator is unhappy with the proposed outages notified to
it under (a), (b) or (c) above, as the case may be, equivalent provisions to those set out
in OC2.4.1.2.1 (d) will apply.
(e) By the end of week 34
NGET will draw up a draft National Electricity Transmission System outage plan
covering the period Years 2 to 5 ahead and NGET will notify each Generator,
Interconnector Owner and Network Operator in writing of those aspects of the plan
which may operationally affect such Generator (other than those aspects which may
operationally affect Embedded Small Power Stations or Embedded Medium Power
Stations), Interconnector Owner or Network Operator. NGET will also indicate where
a need may exist to issue other operational instructions or notifications (including but
not limited to the requirement for the arming of an Operational Intertripping scheme)
or Emergency Instructions to Users in accordance with BC2 to allow the security of
the National Electricity Transmission System to be maintained within the Licence
Standards.
OC2.4.1.3.3
Operational Planning Phase - Planning for Financial Year 1 ahead
Each calendar year NGET shall update the draft National Electricity Transmission
System outage plan prepared under OC2.4.1.3.2 above and shall in addition take into
account outages required as a result of maintenance work.
In each calendar year:
(a) By the end of week 13
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Generators and Non-Embedded Customers will inform NGET in writing of proposed
outages for Year 1 of Generator owned Apparatus at each Grid Entry Point (e.g.
busbar selectors) other than Synchronous Generating Units and/or Power Park
Modules or Non-Embedded Customer owned Apparatus, as the case may be, at
each Grid Supply Point.
(b) By the end of week 28
NGET will provide each Network Operator and each Non-Embedded Customer in
writing with details of proposed outages in Year 1 ahead which may, in NGET's
reasonable judgement, affect the performance of its User System or the NonEmbedded Customer Apparatus at the Grid Supply Point.
(c) By the end of week 32
Each Network Operator will notify NGET in writing with details of proposed outages in
Year 1 in its User System which may affect the performance of the Total System
(which includes but is not limited to outages of User System Apparatus at Grid
Supply Points and outages which constrain the output of Synchronous Generating
Units and/or Power Park Modules Embedded within that User System).
Each Network Operator will notify NGET in writing of details of proposed outages in
Year 1 in its User System which may affect the declared values of Maximum Export
Capacity and/or Maximum Import Capacity for each Interface Point within its User
System together with the Network Operator’s revised best estimate of the Maximum
Export Capacity and/or Maximum Import Capacity during such outages. Network
Operators will also notify NGET of any automatic and/or manual post fault actions that
it intends to utilise or plans to utilise during such outages.
Each Network Operator will also notify NGET in writing of any revisions to Interface
Point Target Voltage/Power Factor data submitted pursuant to PC.A.2.5.4.2.
(d) Between the end of week 32 and the end of week 34
NGET will draw up a revised National Electricity Transmission System outage plan
(which for the avoidance of doubt includes Transmission Apparatus at the
Connection Points).
(e) By the end of week 34
NGET will notify each Generator, Interconnector Owner, and Network Operator, in
writing, of those aspects of the National Electricity Transmission System outage
programme which may, in NGET’s reasonable opinion, operationally affect that
Generator (other than those aspects which may operationally affect Embedded Small
Power Stations or Embedded Medium Power Stations), Interconnector Owner, or
Network Operator including in particular proposed start dates and end dates of
relevant National Electricity Transmission System outages.
NGET will provide to each Network Operator and to each Generator and each
Interconnector Owner a copy of the information given to NGET under paragraph (c)
above (other than the information given by that Network Operator). In relation to a
Network Operator, the data must only be used by that User in planning and operating
that Network Operator’s User System and must not be used for any other purpose or
passed on to, or used by, any other business of that User or to, or by, any person within
any other such business or elsewhere.
(f)
By the end of week 36
Where a Generator, Interconnector Owner or Network Operator is unhappy with the
proposed aspects notified to it under (e) above, equivalent provisions to those set out in
OC2.4.1.2.1 (d) will apply.
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(g) Between the end of week 34 and 49
NGET will draw up a final National Electricity Transmission System outage plan
covering Year 1.
(h) By the end of week 49
(i)
NGET will complete the final National Electricity Transmission System outage
plan for Year 1. The plan for Year 1 becomes the final plan for Year 0 when by
expiry of time Year 1 becomes Year 0.
(ii)
NGET will notify each Generator, each Interconnector Owner and each Network
Operator in writing of those aspects of the plan which may operationally affect
such Generator (other than those aspects which may operationally affect
Embedded Small Power Stations or Embedded Medium Power Stations),
Interconnector Owner or Network Operator including in particular proposed start
dates and end dates of relevant National Electricity Transmission System
outages. NGET will also indicate where a need may exist to issue other operational
instructions or notifications (including but not limited to the requirement for the
arming of an Operational Intertripping scheme) or Emergency Instructions to
Users in accordance with BC2 to allow the security of the National Electricity
Transmission System to be maintained within the Licence Standards. NGET will
also inform each relevant Non-Embedded Customer of the aspects of the plan
which may affect it.
(iii) In addition, in relation to the final National Electricity Transmission System
outage plan for Year 1, NGET will provide to each Generator and each
Interconnector Owner a copy of the final National Electricity Transmission
System outage plan for that year. OC2.4.1.3.4 contains provisions whereby
updates of the final National Electricity Transmission System outage plan are
provided. The plan and the updates will be provided in writing. It should be noted
that the final National Electricity Transmission System outage plan for Year 1
and the updates will not give a complete understanding of how the National
Electricity Transmission System will operate in real time, where the National
Electricity Transmission System operation may be affected by other factors
which may not be known at the time of the plan and the updates. Therefore, Users
should place no reliance on the plan or the updates showing a set of conditions
which will actually arise in real time.
(i)
Information Release Or Exchange
This paragraph (i) contains alternative requirements on NGET, paragraph (z) being an
alternative to a combination of paragraphs (x) and (y). Paragraph (z) will only apply in
relation to a particular User if NGET and that User agree that it should apply, in which
case paragraphs (x) and (y) will not apply. In the absence of any relevant agreement
between NGET and the User, NGET will only be required to comply with paragraphs (x)
and (y).
Information Release To Each Network Operator And Non-Embedded Customer
Between the end of Week 34 and 49 NGET will upon written request:
(x) for radial systems, provide each Network Operator and Non Embedded
Customer with data to allow the calculation by the Network Operator, and each
Non Embedded Customer, of symmetrical and asymmetrical fault levels; and
(y) for interconnected Systems, provide to each Network Operator an equivalent
network, sufficient to allow the identification of symmetrical and asymmetrical fault
levels, and power flows across interconnecting User Systems directly connected
to the National Electricity Transmission System; or
System Data Exchange
(z) as part of a process to facilitate understanding of the operation of the Total
System,
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(1) NGET will make available to each Network Operator, the National
Electricity Transmission System Study Network Data Files covering Year
1 which are of relevance to that User's System;
(2) where NGET and a User have agreed to the use of data links between them,
the making available will be by way of allowing the User access to take a copy
of the National Electricity Transmission System Study Network Data Files
once during that period. The User may, having taken that copy, refer to the
copy as often as it wishes. Such access will be in a manner agreed by NGET
and may be subject to separate agreements governing the manner of access.
In the absence of agreement, the copy of the National Electricity
Transmission System Study Network Data Files will be given to the User
on a disc, or in hard copy, as determined by NGET;
(3) the data contained in the National Electricity Transmission System Study
Network Data Files represents NGET's view of operating conditions although
the actual conditions may be different;
(4) NGET will notify each Network Operator, as soon as reasonably practicable
after it has updated the National Electricity Transmission System Study
Network Data Files covering Year 1 that it has done so, when this update
falls before the next annual update under this OC2.4.1.3.3(i). NGET will then
make available to each Network Operator who has received an earlier
version (and in respect of whom the agreement still exists), the updated
National Electricity Transmission System Study Network Files covering
the balance of Years 1 and 2 which remain given the passage of time, and
which are of relevance to that User's System. The provisions of paragraphs
(2) and (3) above shall apply to the making available of these updates;
(5) the data from the National Electricity Transmission System Study
Network Data Files received by each Network Operator must only be used
by that User in planning and operating that Network Operator’s User
System and must not be used for any other purpose or passed on to, or used
by, any other business of that User or to, or by, any person within any other
such business or elsewhere.
OC2.4.1.3.4
Operational Planning Phase - Planning In Financial Year 0 Down To The Programming
Phase (And In The Case Of Load Transfer Capability, Also During The Programming Phase)
(a) The National Electricity Transmission System outage plan for Year 1 issued under
OC2.4.1.3.3 shall become the plan for Year 0 when by expiry of time Year 1 becomes
Year 0.
(b) Each Generator or Interconnector Owner or Network Operator or Non-Embedded
Customer may at any time during Year 0 request NGET in writing for changes to the
outages requested by them under OC2.4.1.3.3. In relation to that part of Year 0,
excluding the period 1-7 weeks from the date of request, NGET shall determine whether
the changes are possible and shall notify the Generator, Interconnector Owner,
Network Operator or Non-Embedded Customer in question whether this is the case
as soon as possible, and in any event within 14 days of the date of receipt by NGET of
the written request in question.
Where NGET determines that any change so requested is possible and notifies the
relevant User accordingly, NGET will provide to each Network Operator, each
Interconnector Owner, and each Generator a copy of the request to which NGET has
agreed which relates to outages on Systems of Network Operators (other than any
request made by that Network Operator). The information must only be used by that
Network Operator in planning and operating that Network Operator’s User System
and must not be used for any other purpose or passed on to, or used by, any other
business of that User or to, or by, any person within any other such business or
elsewhere.
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(c) During Year 0 (including the Programming Phase) each Network Operator shall at
NGET's request make available to NGET such details of automatic and manual load
transfer capability of:
(i)
12MW or more (averaged over any half hour) for England and Wales
(ii)
10MW or more (averaged over any half hour) for Scotland
between Grid Supply Points.
During Year 0 (including the Programming Phase) each Network Operator shall notify
NGET of any revisions to the information provided pursuant to OC2.4.1.3.3 (c) for
Interface Points as soon as reasonably practicable after the Network Operator
becomes aware of the need to make such revisions.
(d) When necessary during Year 0, NGET will notify each Generator, each Interconnector
Owner and Network Operator and each Non-Embedded Customer, in writing of
those aspects of the National Electricity Transmission System outage programme in
the period from the 8th week ahead to the 52nd week ahead, which may, in NGET's
reasonable opinion, operationally affect that Generator (other than those aspects which
may operationally affect Embedded Small Power Stations or Embedded Medium
Power Stations) Interconnector Owner or Network Operator or Non-Embedded
Customer including in particular proposed start dates and end dates of relevant
National Electricity Transmission System outages.
NGET will also notify changes to information supplied by NGET pursuant to
OC2.4.1.3.3(i)(x) and (y) except where in relation to a User information was supplied
pursuant to OC2.4.1.3.3(i)(z). In that case:(i)
NGET will, by way of update of the information supplied by it pursuant to
OC2.4.1.3.3(i)(z), make available at the first time in Year 0 that it updates the
National Electricity Transmission System Study Network Data Files in respect
of Year 0 (such update being an update on what was shown in respect of Year 1
which has then become Year 0) to each Network Operator who has received an
earlier version under OC2.4.1.3.3(i)(z) (and in respect of whom the agreement still
exists), the National Electricity Transmission System Study Network Data
Files covering Year 0 which are of relevance to that User's System.
(ii)
NGET will notify each relevant Network Operator, as soon as reasonably
practicable after it has updated the National Electricity Transmission System
Study Network Data Files covering Year 0, that it has done so. NGET will then
make available to each such Network Operator, the updated National Electricity
Transmission System Study Network Data Files covering the balance of Year 0
which remains given the passage of time, and which are of relevance to that
User's System.
(iii) The provisions of OC2.4.1.3.3(i)(z)(2), (3) and (5) shall apply to the provision of
data under this part of OC2.4.1.3.4(d) as if set out in full.
NGET will also indicate where a need may exist to issue other operational instructions
or notifications (including but not limited to the requirement for the arming of an
Operational Intertripping scheme) or Emergency Instructions to Users in
accordance with BC2 to allow the security of the National Electricity Transmission
System to be maintained within the Licence Standards.
(e) In addition, by the end of each month during Year 0, NGET will provide to each
Generator and each Interconnector Owner a notice containing any revisions to the
final National Electricity Transmission System outage plan for Year 1, provided to
the Generator or the Interconnector Owner under OC2.4.1.3.3 or previously under
this provision, whichever is the more recent.
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OC2.4.1.3.5
Programming Phase
(a) By 1600 hours each Thursday
(i)
NGET shall continue to update a preliminary National Electricity Transmission
System outage programme for the eighth week ahead, a provisional National
Electricity Transmission System outage programme for the next week ahead
and a final day ahead National Electricity Transmission System outage
programme for the following day.
(ii)
NGET will notify each Generator, Interconnector Owner and Network Operator
and each Non-Embedded Customer, in writing of those aspects of the preliminary
National Electricity Transmission System outage programme which may
operationally affect each Generator (other than those aspects which may
operationally affect Embedded Small Power Stations or Embedded Medium
Power Stations) or Interconnector Owner or Network Operator and each NonEmbedded Customer including in particular proposed start dates and end dates
of relevant National Electricity Transmission System outages.
NGET will also notify changes to information supplied by NGET pursuant to
OC2.4.1.3.3(i)(x) and (y) except where in relation to a User information was
supplied pursuant to OC2.4.1.3.3(i)(z). In that case:
(1) NGET will, by way of update of the information supplied by it pursuant to
OC2.4.1.3.3(i)(z), make available the National Electricity Transmission
System Study Network Data Files for the next week ahead and
(2) NGET will notify each relevant Network Operator, as soon as reasonably
practicable after it has updated the National Electricity Transmission
System Study Network Data Files covering the next week ahead that it has
done so, and
(3) The provisions of OC2.4.1.3.3(i)(z)(2), (3) and (5) shall apply to the provision
of data under this part of OC2.4.1.3.5(a)(ii) as if set out in full.
NGET may make available the National Electricity Transmission System Study
Network Data Files for the next week ahead where NGET and a particular User
agree, and in such case the provisions of OC2.4.1.1.3.3(i)(x) and (y) and the
provisions of OC2.4.1.3.4(d) and OC2.4.1.3.5(a) which relate to OC2.4.1.1.3.3(i)(x)
and (y) shall not apply. In such case the provisions of this OC2.4.1.3.5(a)(ii)2 and 3
shall apply to the provision of the data under this part of OC2.4.1.3.5(a)(ii) as if set
out in full.
NGET will also indicate where a need may exist to arm an Operational
Intertripping scheme, emergency switching, emergency Demand management or
other measures including the issuing of other operational instructions or
notifications or Emergency Instructions to Users in accordance with BC2 to allow
the security of the National Electricity Transmission System to be maintained
within the Licence Standards.
(b) By 1000 hours each Friday
Generators, Interconnector Owners and Network Operators will discuss with NGET
and confirm in writing to NGET, acceptance or otherwise of the requirements detailed
under OC2.4.1.3.5.
Network Operators shall confirm for the following week:
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(i)
the details of any outages of its User System that will restrict the Maximum
Export Capacity and/or Maximum Import Capacity at any Interface Points
within its User System for the following week; and
(ii)
any changes to the previously declared values of the Interface Point Target
Voltage/Power Factor.
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(c) By 1600 hours each Friday
(i)
NGET shall finalise the preliminary National Electricity Transmission System
outage programme up to the seventh week ahead. NGET will endeavour to give
as much notice as possible to a Generator with nuclear Large Power Stations
which may be operationally affected by an outage which is to be included in such
programme.
(ii)
NGET shall finalise the provisional National Electricity Transmission System
outage programme for the next week ahead.
(iii) NGET shall finalise the National Electricity Transmission System outage
programme for the weekend through to the next normal working day.
(iv) In each case NGET will indicate the factors set out in (a)(ii) above (other than
those aspects which may operationally affect Embedded Small Power Stations
or Embedded Medium Power Stations) to the relevant Generators and Network
Operators and Non-Embedded Customers.
(v) Where a Generator with nuclear Large Power Stations which may be
operationally affected by the preliminary National Electricity Transmission
System outage programme referred to in (i) above (acting as a reasonable
operator) is concerned on grounds relating to safety about the effect which an
outage within such outage programme might have on one or more of its nuclear
Large Power Stations, it may contact NGET to explain its concerns and discuss
whether there is an alternative way of taking that outage (having regard to
technical feasibility). If there is such an alternative way, but NGET refuses to adopt
that alternative way in taking that outage, that Generator may involve the
Disputes Resolution Procedure to decide on the way the outage should be
taken. If there is no such alternative way, then NGET may take the outage despite
that Generator's concerns.
(d) By 1600 hours each Monday, Tuesday, Wednesday and Thursday
(i)
NGET shall prepare a final National Electricity Transmission System outage
programme for the following day.
(ii)
NGET shall notify each Generator and Network Operator and Non-Embedded
Customer in writing of the factors set out in (a)(ii) above (other than those aspects
which may operationally affect Embedded Small Power Stations or Embedded
Medium Power Stations).
OC2.4.2
DATA REQUIREMENTS
OC2.4.2.1
When a Statement of Readiness under the Bilateral Agreement and/or Construction
Agreement is submitted, and thereafter in calendar week 24 in each calendar year,
(a) each Generator shall (subject to OC2.4.2.1(k)) in respect of each of its:(i)
Gensets (in the case of the Generation Planning Parameters); and
(ii)
CCGT Units within each of its CCGT Modules at a Large Power Station (in the
case of the Generator Performance Chart)
submit to NGET in writing the Generation Planning Parameters and the Generator
Performance Chart.
(b) Each shall meet the requirements of CC.6.3.2 and shall reasonably reflect the true
operating characteristics of the Genset.
(c) They shall be applied (unless revised under this OC2 or (in the case of the Generator
Performance Chart only) BC1 in relation to Other Relevant Data) from the
Completion Date, in the case of the ones submitted with the Statement of Readiness,
and in the case of the ones submitted in calendar week 24, from the beginning of week
25 onwards.
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(d) They shall be in the format indicated in Appendix 1 for these charts and as set out in
Appendix 2 for the Generation Planning Parameters.
(e) Any changes to the Generator Performance Chart or Generation Planning
Parameters should be notified to NGET promptly.
(f)
Generators should note that amendments to the composition of the CCGT Module or
Power Park Module at Large Power Stations may only be made in accordance with
the principles set out in PC.A.3.2.3 or PC.A.3.2.4 respectively. If in accordance with
PC.A.3.2.3 or PC.A.3.2.4 an amendment is made, any consequential changes to the
Generation Planning Parameters should be notified to NGET promptly.
(g) The Generator Performance Chart must be as described below and demonstrate the
limitation on reactive capability of the System voltage at 3% above nominal. It must
also include any limitations on output due to the prime mover (both maximum and
minimum), Generating Unit step up transformer or User System.
(i)
For a Synchronous Generating Unit on a Generating Unit specific basis at the
Generating Unit Stator Terminals. It must include details of the Generating Unit
transformer parameters.
(ii)
For a Non-Synchronous Generating Unit (excluding a Power Park Unit) on a
Generating Unit specific basis at the Grid Entry Point (or User System Entry
Point if Embedded).
(iii) For a Power Park Module, on a Power Park Module specific basis at the Grid
Entry Point (or User System Entry Point if Embedded).
(iv) For a DC Converter on a DC Converter specific basis at the Grid Entry Point (or
User System Entry Point if Embedded).
(h) For each CCGT Unit, and any other Generating Unit or Power Park Module whose
performance varies significantly with ambient temperature, the Generator Performance
Chart shall show curves for at least two values of ambient temperature so that NGET
can assess the variation in performance over all likely ambient temperatures by a
process of linear interpolation or extrapolation. One of these curves shall be for the
ambient temperature at which the Generating Unit's output, or CCGT Module at a
Large Power Station output or Power Park Module’s output, as appropriate, equals
its Registered Capacity.
(i)
The Generation Planning Parameters supplied under OC2.4.2.1 shall be used by
NGET for operational planning purposes only and not in connection with the operation
of the Balancing Mechanism (subject as otherwise permitted in the BC).
(j)
Each Generator shall in respect of each of its CCGT Modules at Large Power
Stations submit to NGET in writing a CCGT Module Planning Matrix. It shall be
prepared on a best estimate basis relating to how it is anticipated the CCGT Module will
be running and which shall reasonably reflect the true operating characteristics of the
CCGT Module. It will be applied (unless revised under this OC2) from the Completion
Date, in the case of the one submitted with the Statement of Readiness, and in the
case of the one submitted in calendar week 24, from the beginning of week 31 onwards.
It must show the combination of CCGT Units which would be running in relation to any
given MW output, in the format indicated in Appendix 3.
Any changes must be notified to NGET promptly. Generators should note that
amendments to the composition of the CCGT Module at Large Power Stations may
only be made in accordance with the principles set out in PC.A.3.2.3. If in accordance
with PC.A.3.2.3 an amendment is made, an updated CCGT Module Planning Matrix
must be immediately submitted to NGET in accordance with this OC2.4.2.1(b).
The CCGT Module Planning Matrix will be used by NGET for operational planning
purposes only and not in connection with the operation of the Balancing Mechanism.
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(k) Each Generator shall in respect of each of its Cascade Hydro Schemes also submit
the Generation Planning Parameters detailed at OC2.A.2.6 to OC2.A.2.10 for each
Cascade Hydro Scheme. Such parameters need not also be submitted for the
individual Gensets within such Cascade Hydro Scheme.
(l)
Each Generator shall in respect of each of its Power Park Modules at Large Power
Stations submit to NGET in writing a Power Park Module Planning Matrix. It shall be
prepared on a best estimate basis relating to how it is anticipated the Power Park
Module will be running and which shall reasonably reflect the operating characteristics
of the Power Park Module and the BM Unit of which it forms part. It will be applied
(unless revised under this OC2) from the Completion Date, in the case of the one
submitted with the Statement of Readiness, and in the case of the one submitted in
calendar week 24, from the beginning of week 31 onwards. It must show the number of
each type of Power Park Unit in the Power Park Module typically expected to be
available to generate and the BM Unit of which it forms part, in the format indicated in
Appendix 4. The Power Park Module Planning Matrix shall be accompanied by a
graph showing the variation in MW output with Intermittent Power Source (e.g. MW vs
wind speed) for the Power Park Module. The graph shall indicate the typical value of
the Intermittent Power Source for the Power Park Module.
Any changes must be notified to NGET promptly. Generators should note that
amendments to the composition of the Power Park Module at Large Power Stations
may only be made in accordance with the principles set out in PC.A.3.2.4. If in
accordance with PC.A.3.2.4 an amendment is made, an updated Power Park Module
Planning Matrix must be immediately submitted to NGET in accordance with this
OC2.4.2.1(a).
The Power Park Module Planning Matrix will be used by NGET for operational
planning purposes only and not in connection with the operation of the Balancing
Mechanism.
(m) For each Synchronous Generating Unit where the Generator intends to adjust the
Generating Unit terminal voltage in response to a MVAr Output Instruction or a Target
Voltage Level instruction in accordance with BC2.A.2.6 the Generator Performance
Chart shall show curves corresponding to the Generating Unit terminal voltage being
controlled to its rated value and to its maximum value.
OC2.4.2.2
Each Network Operator shall by 1000 hrs on the day falling seven days before each
Operational Day inform NGET in writing of any changes to the circuit details called for in
PC.A.2.2.1 which it is anticipated will apply on that Operational Day (under BC1 revisions
can be made to this data).
OC2.4.2.3
Under European Commission Regulation No. 543/2013, Users are required to submit certain
data for publication on the Central European Transparency Platform managed by the
European Network of Transmission System Operators for Electricity (ENTSO-E). NGET is
required to facilitate the collection, verification and processing of data from Users for onward
transmission to the Central European Transparency Platform.
Each Generator and each Non-Embedded Customer connected to or using the National
Electricity Transmission System shall provide NGET with such information as required by
and set out in DRC Schedule 6 (Users’ Outage Data EU Transparency Availability Data) in
the timescales detailed therein.
OC2.4.3
NEGATIVE RESERVE ACTIVE POWER MARGINS
OC2.4.3.1
In each calendar year, by the end of week 39 NGET will, taking into account the Final
Generation Outage Programme and forecast of Output Usable supplied by each
Generator and by each Interconnector Owner, issue a notice in writing to:(a) all Generators with Large Power Stations and to all Interconnector Owners listing
any period in which there is likely to be an unsatisfactory System NRAPM; and
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(b) all Generators with Large Power Stations and to all Interconnector Owners which
may, in NGET's reasonable opinion be affected, listing any period in which there is
likely to be an unsatisfactory Localised NRAPM, together with the identity of the
relevant System Constraint Group or Groups,
within the next calendar year, together with the margin. NGET and each Generator and
each Interconnector Owner will take these into account in seeking to co-ordinate outages
for that period.
OC2.4.3.2
(a) By 0900 hours each Business Day
Each Generator shall provide NGET in writing with a best estimate of Genset
inflexibility on a daily basis for the period 2 to 14 days ahead (inclusive).
(b) By 1600 hours each Wednesday
Each Generator shall provide NGET in writing with a best estimate of Genset
inflexibility on a weekly basis for the period 2 to 7 weeks ahead (inclusive).
(c) Between 1600 hours each Wednesday and 1200 hours each Friday
(i)
If NGET, taking into account the estimates supplied by Generators under (b)
above, and forecast Demand for the period, foresees that:
(1) the level of the System NRAPM for any period within the period 2 to 7 weeks
ahead (inclusive) is too low, it will issue a notice in writing to all Generators,
Interconnector Owners, and Network Operators listing any periods and
levels of System NRAPM within that period; and/or
(2) having also taken into account the appropriate limit on transfers to and from a
System Constraint Group, the level of Localised NRAPM for any period
within the period 2 to 7 weeks ahead (inclusive) is too low for a particular
System Constraint Group, it will issue a notice in writing to all Generators,
Interconnector Owners, and Network Operators which may, in NGET's
reasonable opinion be affected by that Localised NRAPM, listing any periods
and levels of Localised NRAPM within that period. A separate notice will be
given in respect of each affected System Constraint Group.
Outages Adjustments
(ii)
NGET will then contact Generators in respect of their Large Power Stations and
Interconnector Owners to discuss outages as set out in the following paragraphs
of this OC2.4.3.2.
(iii) NGET will contact all Generators and Interconnector Owners in the case of low
System NRAPM and will contact Generators in relation to relevant Large Power
Stations and Interconnector Owners in the case of low Localised NRAPM.
NGET will raise with each Generator and Interconnector Owner the problems it
is anticipating due to the low System NRAPM or Localised NRAPM and will
discuss:
(1) whether any change is possible to the estimate of Genset inflexibility given
under (b) above; and
(2) whether Genset or External Interconnection outages can be taken to
coincide with the periods of low System NRAPM or Localised NRAPM (as
the case may be).
In relation to Generators with nuclear Large Power Stations the discussions on
outages can include the issue of whether outages can be taken for re-fuelling
purposes to coincide with the relevant low System NRAPM and/or Localised
NRAPM periods.
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(iv) If agreement is reached with a Generator or an Interconnector Owner (which
unlike the remainder of OC2 will constitute a binding agreement), then such
Generator or Interconnector Owner will take such outage, as agreed with NGET,
and NGET will issue a revised notice in writing to the Generators, Interconnector
Owners, and Network Operators to which it sent notices under (i) above,
reflecting the changes brought about to the periods and levels of System NRAPM
and/or Localised NRAPM by the agreements with Generators or Interconnector
Owners.
(d) By 1600 hours each day
(i)
If NGET, taking into account the estimates supplied under (a) above, and forecast
Demand for the period, foresees that:
(1) the level of System NRAPM for any period within the period of 2 to 14 days
ahead (inclusive) is too low, it will issue a notice in writing to all Generators,
Interconnector Owners, and Network Operators listing the periods and
levels of System NRAPM within those periods; and/or
(2) having also taken into account the appropriate limit on transfers to and from a
System Constraint Group, the level of Localised NRAPM for any period
within the period of 2 to 14 days ahead (inclusive) is too low for a particular
System Constraint Group, it will issue a notice in writing to all Generators,
Interconnector Owners, and Network Operators which may, in NGET's
reasonable opinion be affected by that Localised NRAPM, listing any periods
and levels of Localised NRAPM within that period. A separate notice will be
given in respect of each affected System Constraint Group.
(ii) NGET will contact all Generators in respect of their Large Power Stations (or in
the case of Localised NRAPM, all Generators which may, in NGET's reasonable
opinion be affected, in respect of their relevant Large Power Stations) to discuss
whether any change is possible to the estimate of Genset inflexibility given under
(a) above and to consider Large Power Station outages to coincide with the
periods of low System NRAPM and/or Localised NRAPM (as the case may be).
In the case of External Interconnections, NGET may contact Interconnector
Owners to discuss outages during the periods of low System NRAPM and/or
Localised NRAPM (as the case may be).
(e) If on the day prior to a Operational Day, it is apparent from the BM Unit Data
submitted by Users under BC1 that System NRAPM and/or Localised NRAPM (as the
case may be) is, in NGET's reasonable opinion, too low, then in accordance with the
procedures and requirements set out in BC1.5.5 NGET may contact Users to discuss
whether changes to Physical Notifications are possible, and if they are, will reflect
those in the operational plans for the next following Operational Day or will, in
accordance with BC2.9.4 instruct Generators to De-Synchronise a specified Genset
for such period. In determining which Genset to so instruct, BC2 provides that NGET
will not (other than as referred to below) consider in such determination (and
accordingly shall not instruct to De-Synchronise) any Genset within an Existing Gas
Cooled Reactor Plant. BC2 further provides that:(i)
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NGET is permitted to instruct to De-Synchronise any Gensets within an Existing
AGR Plant if those Gensets within an Existing AGR Plant have failed to offer to
be flexible for the relevant instance at the request of NGET provided the request is
within the Existing AGR Plant Flexibility Limit.
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(ii)
OC2.4.4
NGET will only instruct to De-Synchronise any Gensets within an Existing
Magnox Reactor Plant or within an Existing AGR Plant (other than under (i)
above) if the level of System NRAPM (taken together with System constraints)
and/or Localised NRAPM is such that it is not possible to avoid DeSynchronising such Generating Unit, and provided the power flow across each
External Interconnection is either at zero or results in an export of power from the
Total System. This proviso applies in all cases in the case of System NRAPM
and in the case of Localised NRAPM, only when the power flow would have a
relevant effect.
FREQUENCY SENSITIVE OPERATION
By 1600 hours each Wednesday
OC2.4.4.1
Using such information as NGET shall consider relevant including, if appropriate, forecast
Demand, any estimates provided by Generators of Genset inflexibility and anticipated plant
mix relating to operation in Frequency Sensitive Mode, NGET shall determine for the
period 2 to 7 weeks ahead (inclusive) whether it is possible that there will be insufficient
Gensets (other than those Gensets within Existing Gas Cooled Reactor Plant which are
permitted to operate in Limited Frequency Sensitive Mode at all times under BC3.5.3) to
operate in Frequency Sensitive Mode for all or any part of that period.
OC2.4.4.2
BC3.5.3 explains that NGET permits Existing Gas Cooled Reactor Plant other than
Frequency Sensitive AGR Units to operate in a Limited Frequency Sensitive Mode at all
times.
OC2.4.4.3
If NGET foresees that there will be an insufficiency in Gensets operating in a Frequency
Sensitive Mode, it will contact Generators in order to seek to agree (as soon as reasonably
practicable) that all or some of the Gensets (the MW amount being determined by NGET but
the Gensets involved being determined by the Generator) will take outages to coincide with
such period as NGET shall specify to enable replacement by other Gensets which can
operate in a Frequency Sensitive Mode. If agreement is reached (which unlike the
remainder of OC2 will constitute a binding agreement) then such Generator will take such
outage as agreed with NGET. If agreement is not reached, then the provisions of BC2.9.5
may apply.
OC2.4.5
If in NGET's reasonable opinion it is necessary for both the procedure set out in OC2.4.3
(relating to System NRAPM and Localised NRAPM) and in OC2.4.4 (relating to operation
in Frequency Sensitive Mode) to be followed in any given situation, the procedure set out
in OC2.4.3 will be followed first, and then the procedure set out in OC2.4.4. For the
avoidance of doubt, nothing in this paragraph shall prevent either procedure from being
followed separately and independently of the other.
OC2.4.6
OPERATING MARGIN DATA REQUIREMENTS
OC2.4.6.1
Modifications to relay settings
‘Relay settings’ in this OC2.4.6.1 refers to the settings of Low Frequency Relays in respect
of Gensets that are available for start from standby by Low Frequency Relay initiation with
Fast Start Capability agreed pursuant to the Bilateral Agreement.
By 1600 hours each Wednesday
A change in relay settings will be sent by NGET no later than 1600 hours on a
Wednesday to apply from 1000 hours on the Monday following. The settings allocated
to particular Large Power Stations may be interchanged between 49.70Hz and
49.60Hz (or such other System Frequencies as NGET may have specified) provided
the overall capacity at each setting and System requirements can, in NGET's view, be
met.
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Between 1600 hours each Wednesday and 1200 hours each Friday
If a Generator wishes to discuss or interchange settings it should contact NGET by
1200 hours on the Friday prior to the Monday on which it would like to institute the
changes to seek NGET's agreement. If NGET agrees, NGET will then send
confirmation of the agreed new settings.
By 1500 hours each Friday
If any alterations to relay settings have been agreed, then the updated version of the
current relay settings will be sent to affected Users by 1500 hours on the Friday prior to
the Monday on which the changes will take effect. Once accepted, each Generator (if
that Large Power Station is not subject to forced outage or Planned Outage) will
abide by the terms of its latest relay settings.
In addition, NGET will take account of any Large Power Station unavailability (as
notified under OC2.4.1.2 submissions) in its total Operating Reserve policy.
NGET may from time to time, for confirmation purposes only, issue the latest version of
the current relay settings to each affected Generator
OC2.4.6.2
Operating Margins
By 1600 hours each Wednesday
No later than 1600 hours on a Wednesday, NGET will provide an indication of the level of
Operating Reserve to be utilised by NGET in connection with the operation of the
Balancing Mechanism in the week beginning with the Operational Day commencing
during the subsequent Monday, which level shall be purely indicative.
This Operating Margin indication will also note the possible level of Operating Reserve (if
any) which may be provided by Interconnector Users in the week beginning with the
Operational Day commencing during the subsequent Monday.
This Operating Margin indication will also note the possible level of High Frequency
Response to be utilised by NGET in connection with the operation of the Balancing
Mechanism in the week beginning with the Operational Day commencing during the
subsequent Monday, which level shall be purely indicative.
OC2.4.7
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In the event that:
a)
a Non-Embedded Customer experiences the planned unavailability of its Apparatus
resulting in the reduction of Demand of 100MW or more, or a change to the planned
unavailability of its Apparatus resulting in a change in Demand of 100MW or more, for
one Settlement Period or longer; or
b)
a Non-Embedded Customer experiences a change in the actual availability of its
Apparatus resulting in a change in Demand of 100MW or greater; or
c)
a Generator experiences a planned unavailability of a Generating Unit resulting in a
change of 100MW or more in the Output Usable of that Generating Unit below its
previously notified availability, which is expected to last one Settlement Period or
longer and up to three years ahead; or
d)
a Generator experiences a change of 100Mw or more in the Maximum Export Limit of
a Generating Unit which is expected to last one Settlement Period or longer; or
e)
a Generator experiences a planned unavailability resulting in a change of 100MW or
more in its aggregated Output Usable below its previously notified availability for a
Power Station with a Registered Capacity of 200MW or more and which is expected
to last one Settlement Period or longer and up to three years ahead, save where
data has been provided pursuant to OC.2.4.7(c) above; or
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f)
a Generator experiences a change of 100MW or more in the aggregated Maximum
Export Limit of a Power Station with a Registered Capacity of 200MW or more,
which is expected to last one Settlement Period or longer, save where data has been
provided pursuant to OC.2.4.7(d) above;
such Non-Embedded Customer or Generator shall provide NGET with the EU
Transparency Availability Data in accordance with DRC Schedule 6 (Users’ Outage Data)
using MODIS and, with reference to points OC2.4.7(a) to (f), EU Transparency Regulation
articles 7.1(a), 7.1(b), 15.1(a), 15.1(b), 15.1(c) and 15.1(d) respectively.
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E) User System
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Where a Reactive Despatch Network Restriction is in place which requires
following of local voltage conditions, alternatively to (E), please check this box.
(E)
APPENDIX 1 - PERFORMANCE CHARTS
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POWER PARK MODULE PERFORMANCE CHART AT THE CONNECTION POINT OR USER’S SYSTEM
ENTRY POINT
Rated MW
Output
100%
MW
F
G
50%
20%
A
E C
D
B
LEADING
MVAr
LAGGING
Point A is equivalent (in MVAr) to:
0.95 leading Power Factor at Rated MW output
Point B is equivalent (in MVAr) to:
0.95 lagging Power Factor at Rated MW output
Point C is equivalent (in MVAr) to:
-5% of Rated MW output
Point D is equivalent (in MVAr) to:
+5% of Rated MW output
Point E is equivalent (in MVAr) to:
-12% of Rated MW output
Line F is equivalent (in MVAr) to:
Leading Power Factor Reactive Despatch Network Restriction
Line G is equivalent (in MVAr) to:
Lagging Power Factor Reactive Despatch Network Restriction
Where a Reactive Despatch Network Restriction is in place which requires
following of local voltage conditions, alternatively to Line F and G, please check
this box.
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APPENDIX 2 - GENERATION PLANNING PARAMETERS
OC2.A.2
Generation Planning Parameters
The following parameters are required in respect of each Genset.
OC2.A.2.1
Regime Unavailability
Where applicable the following information must be recorded for each Genset.
-
Earliest synchronising time:
Monday
Tuesday to Friday
Saturday to Sunday
-
Latest de-synchronising time:
Monday to Thursday
Friday
Saturday to Sunday
OC2.A.2.2
Synchronising Intervals
(a) The Synchronising interval between Gensets in a Synchronising Group assuming all
Gensets have been Shutdown for 48 hours;
(b) The Synchronising Group within the Power Station to which each Genset should be
allocated.
OC2.A.2.3
De-Synchronising Interval
A fixed value De-Synchronising interval between Gensets within a Synchronising Group.
OC2.A.2.4
Synchronising Generation
The amount of MW produced at the moment of Synchronising assuming the Genset has
been Shutdown for 48 hours.
OC2.A.2.5
Minimum Non-zero time (MNZT)
The minimum period on-load between Synchronising and De-Synchronising assuming the
Genset has been Shutdown for 48 hours.
OC2.A.2.6
Run-Up rates
A run-up characteristic consisting of up to three stages from Synchronising Generation to
Output Usable with up to two intervening break points assuming the Genset has been
Shutdown for 48 hours.
OC2.A.2.7
Run-down rates
A run down characteristic consisting of up to three stages from Output Usable to DeSynchronising with breakpoints at up to two intermediate load levels.
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OC2.A.2.8
Notice to Deviate from Zero (NDZ)
The period of time normally required to Synchronise a Genset following instruction from
NGET assuming the Genset has been Shutdown for 48 hours.
OC2.A.2.9
Minimum Zero time (MZT)
The minimum interval between De-Synchronising and Synchronising a Genset.
OC2.A.2.10
Not used.
OC2.A.2.11
Gas Turbine Units loading parameters
Issue 5 Revision 18
-
Loading rate for fast starting
-
Loading rate for slow starting
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APPENDIX 3 - CCGT MODULE PLANNING MATRIX
CCGT Module Planning Matrix Example Form
CCGT GENERATING UNITS AVAILABLE
CCGT MODULE
1st
GT
2nd
GT
3rd
GT
OUTPUT USABLE
4th
GT
5th
GT
6th
GT
1st
ST
2nd
ST
3rd
ST
OUTPUT USABLE
150
150
150
100
MW
0MW to 150MW
151MW to 250MW
251MW to 300MW
301MW to 400MW
401MW to 450MW
451MW to 550MW
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/
/
/
/
/
/
/
/
/
/
/
/
/
/
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APPENDIX 4 - POWER PARK MODULE PLANNING MATRIX
Power Park Module Planning Matrix Example Form
BM Unit Name
Power Park Module [unique identifier]
POWER PARK UNITS
POWER PARK
UNIT AVAILABILITY
Type A
Type B
Type C
Type D
Description
(Make/Model)
Number of units
Power Park Module [unique identifier]
POWER PARK UNITS
POWER PARK
UNIT AVAILABILITY
Type A
Type B
Type C
Type D
Description
(Make/Model)
Number of units
The Power Park Module Planning Matrix may have as many columns as are required to provide
information on the different make and model for each type of Power Park Unit in a Power Park Module and
as many rows as are required to provide information on the Power Park Modules within each BM Unit. The
description is required to assist identification of the Power Park Units within the Power Park Module and
correlation with data provided under the Planning Code.
< END OF OPERATING CODE NO. 2 >
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OPERATING CODE NO. 3
(OC3)
NOT USED
< END OF OPERATING CODE NO. 3 >
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OC3
i
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OPERATING CODE NO. 4
(OC4)
NOT USED
< END OF OPERATING CODE NO. 4 >
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OPERATING CODE NO. 5
(OC5)
TESTING AND MONITORING
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
OC5.1 INTRODUCTION ................................................................................................................................ 2
OC5.2 OBJECTIVE ........................................................................................................................................ 3
OC5.3 SCOPE ............................................................................................................................................... 3
OC5.4 MONITORING .................................................................................................................................... 3
OC5.4.1 Parameters To Be Monitored .................................................................................................... 3
OC5.4.2 Procedure For Monitoring ......................................................................................................... 3
OC5.5 PROCEDURE FOR TESTING ............................................................................................................ 4
OC5.5.1 NGET Instruction For Testing ................................................................................................... 4
OC5.5.2 User Request For Testing ......................................................................................................... 5
OC5.5.3 Conduct Of Test ....................................................................................................................... 5
OC5.5.4 Test And Monitoring Assessment ............................................................................................. 5
OC5.5.5 Test Failure / Re-test ................................................................................................................ 8
OC5.5.6 Dispute Following Re-test ......................................................................................................... 9
OC5.6 DISPUTE RESOLUTION .................................................................................................................... 9
OC5.7 BLACK START TESTING ................................................................................................................... 9
OC5.7.1 General .................................................................................................................................... 9
OC5.7.2 Procedure For A Black Start Test ........................................................................................... 10
OC5.8 PROCEDURES APPLYING TO EMBEDDED MEDIUM POWER STATION NOT SUBJECT
TO A BILATERAL AGREEMENT AND EMBEDDED DC CONVERTER STATIONS NOT SUBJECT
TO A BILATERAL AGREEMENT ................................................................................................................... 11
APPENDIX 1 - ONSITE SIGNAL PROVISION FOR WITNESSING TESTS ................................................... 13
APPENDIX 2 - COMPLIANCE TESTING OF SYNCHRONOUS PLANT ........................................................ 16
APPENDIX 3 - COMPLIANCE TESTING OF POWER PARK MODULES ...................................................... 26
APPENDIX 4 - COMPLIANCE TESTING FOR DC CONVERTERS AT A DC CONVERTER STATION ......... 36
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OC5.1
INTRODUCTION
Operating Code No. 5 ("OC5") specifies the procedures to be followed by NGET in carrying
out:
(a) monitoring
(i)
of BM Units against their expected input or output;
(ii)
of compliance by Users with the CC and in the case of response to Frequency,
BC3; and
(iii) of the provision by Users of Ancillary Services which they are required or have
agreed to provide; and
(b) the following tests (which are subject to System conditions prevailing on the day):
(i)
tests on Gensets, CCGT Modules, Power Park Modules, DC Converters,
OTSUA (prior to the OTSUA Transfer Time) and Generating Units (excluding
Power Park Units) to test that they have the capability to comply with the CC and,
in the case of response to Frequency, BC3 and to provide the Ancillary Services
that they are either required or have agreed to provide;
(ii)
tests on BM Units, to ensure that the BM Units are available in accordance with
their submitted Export and Import Limits, QPNs, Joint BM Unit Data and
Dynamic Parameters.
The OC5 tests include the Black Start Test procedure.
OC5 also specifies in OC5.8 the procedures which apply to the monitoring and testing of
Embedded Medium Power Stations not subject to a Bilateral Agreement and Embedded
DC Converter Stations not subject to a Bilateral Agreement.
In respect of a Cascade Hydro Scheme the provisions of OC5 shall be applied as follows:
(a) in respect of the BM Unit for the Cascade Hydro Scheme the parameters referred to at
OC5.4.1 (a) and (c) in respect of Commercial Ancillary Services will be monitored and
tested;
(b) in respect of each Genset forming part of the Cascade Hydro Scheme the parameters
referred to at OC5.4.1 (a), (b) and (c) will be tested and monitored. In respect of
OC5.4.1 (a) the performance of the Gensets will be tested and monitored against their
expected input or output derived from the data submitted under BC1.4.2(a)(2). Where
necessary to give effect to the requirements for Cascade Hydro Schemes in the
following provisions of OC5 the term Genset will be read and construed in the place of
BM Unit.
In respect of Embedded Exemptable Large Power Stations the provisions of OC5 shall be
applied as follows:
(a) where there is a BM Unit registered in the BSC in respect of Generating Units the
provisions of OC5 shall apply as written;
(b) in all other cases, in respect of each Generating Unit the parameters referred to at
OC5.4.1(a), (b) and (c) will be tested and monitored. In respect of OC5.4.1(a) the
performance of the Generating Unit will be tested and monitored against their expected
input or output derived from the data submitted under BC1.4.2(a)(2). Where necessary
to give effect to the requirements for such Embedded Exemptable Large Power
Stations in the provisions of OC5 the term Generating Unit will be read and construed
in place of BM Unit.
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OC5.2
OBJECTIVE
The objectives of OC5 are to establish:
(a) that Users comply with the CC (including in the case of OTSUA prior to the OTSUA
Transfer Time);
(b) whether BM Units operate in accordance with their expected input or output derived
from their Final Physical Notification Data and agreed Bid-Offer Acceptances issued
under BC2;
(c) whether each BM Unit is available as declared in accordance with its submitted Export
and Import Limits, QPN, Joint BM Unit Data and Dynamic Parameters; and
(d) whether Generators, DC Converter Station owners and Suppliers can provide those
Ancillary Services which they are either required or have agreed to provide.
In certain limited circumstances as specified in this OC5 the output of CCGT Units may be
verified, namely the monitoring of the provision of Ancillary Services and the testing of
Reactive Power and automatic Frequency Sensitive Operation.
OC5.3
SCOPE
OC5 applies to NGET and to Users, which in OC5 means:
(a) Generators (including those undertaking OTSDUW);
(b) Network Operators;
(c) Non-Embedded Customers;
(d) Suppliers; and
(e) DC Converter Station owners.
OC5.4
MONITORING
OC5.4.1
Parameters To Be monitored
NGET will monitor the performance of:
(a) BM Units against their expected input or output derived from their Final Physical
Notification Data and agreed Bid-Offer Acceptances issued under BC2;
(b) compliance by Users with the CC; and
(c) the provision by Users of Ancillary Services which they are required or have agreed to
provide.
OC5.4.2
Procedure For Monitoring
OC5.4.2.1
In the event that a BM Unit fails persistently, in NGET's reasonable view, to follow, in any
material respect, its expected input or output or a User fails persistently to comply with the
CC and in the case of response to Frequency, BC3 or to provide the Ancillary Services it
is required, or has agreed, to provide, NGET shall notify the relevant User giving details of
the failure and of the monitoring that NGET has carried out.
OC5.4.2.2
The relevant User will, as soon as possible, provide NGET with an explanation of the
reasons for the failure and details of the action that it proposes to take to:
(a) enable the BM Unit to meet its expected input or output or to provide the Ancillary
Services it is required or has agreed to provide, within a reasonable period, or
(b) in the case of a Generating Unit (excluding a Power Park Unit), CCGT Module,
Power Park Module, OTSUA (prior to the OTSUA Transfer Time) or DC Converter to
comply with the CC and in the case of response to Frequency, BC3 or to provide the
Ancillary Services it is required or has agreed to provide, within a reasonable period.
OC5.4.2.3
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NGET and the User will then discuss the action the User proposes to take and will
endeavour to reach agreement as to:
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(a) any short term operational measures necessary to protect other Users; and
(b) the parameters which are to be submitted for the BM Unit and the effective date(s) for
the application of the agreed parameters.
OC5.4.2.4
In the event that agreement cannot be reached within 10 days of notification of the failure by
NGET to the User, NGET or the User shall be entitled to require a test, as set out in OC5.5
and OC5.6, to be carried out.
OC5.5
PROCEDURE FOR TESTING
OC5.5.1
NGET Instruction For Testing
OC5.5.1.1
NGET may at any time (although not normally more than twice in any calendar year in
respect of any particular BM Unit) issue an instruction requiring a User to carry out a test,
provided NGET has reasonable grounds of justification based upon:
(a) a failure to agree arising from the process in CP.8.1; or
(b) monitoring carried out in accordance with OC5.4.2.
OC5.5.1.2
The test, referred to in OC5.5.1.1 and carried out at a time no sooner than 48 hours from the
time that the instruction was issued, on any one or more of the User’s BM Units should only
be to demonstrate that the relevant BM Unit:
(a) if active in the Balancing Mechanism, meets the ability to operate in accordance with
its submitted Export and Import Limits, QPN, Joint BM Unit Data and Dynamic
Parameters and achieve its expected input or output which has been monitored under
OC5.4; and
(b) meets the requirements of the paragraphs in the CC which are applicable to such BM
Units; and
in the case of a BM Unit comprising a Generating Unit, a CCGT Module, a Power Park
Module or a DC Converter meets,
(c) the requirements for operation in Frequency Sensitive Mode and compliance with the
requirements for operation in Limited Frequency Sensitive Mode in accordance with
CC.6.3.3, BC3.5.2 and BC3.7.2; or
(d) the terms of the applicable Supplemental Agreement agreed with the Generator to
have a Fast Start Capability; or
(e) the Reactive Power capability registered with NGET under OC2 which shall meet the
requirements set out in CC.6.3.2. In the case of a test on a Generating Unit within a
CCGT Module the instruction need not identify the particular CCGT Unit within the
CCGT Module which is to be tested, but instead may specify that a test is to be carried
out on one of the CCGT Units within the CCGT Module.
OC5.5.1.3
(a) The instruction referred to in OC5.5.1.1 may only be issued if the relevant User has
submitted Export and Import Limits which notify that the relevant BM Unit is available
in respect of the Operational Day current at the time at which the instruction is issued.
The relevant User shall then be obliged to submit Export and Import Limits with a
magnitude greater than zero for that BM Unit in respect of the time and the duration
that the test is instructed to be carried out, unless that BM Unit would not then be
available by reason of forced outage or Planned Outage expected prior to this
instruction.
(b) In the case of a CCGT Module the Export and Import Limits data must relate to the
same CCGT Units which were included in respect of the Operational Day current at
the time at which the instruction referred to in OC5.5.1.1 is issued and must include, in
relation to each of the CCGT Units within the CCGT Module, details of the various data
set out in BC1.A.1.3 and BC1.A.1.5, which parameters NGET will utilise in instructing in
accordance with this OC5 in issuing Bid-Offer Acceptances. The parameters shall
reasonably reflect the true operating characteristics of each CCGT Unit.
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(c) The test referred to in OC5.5.1.1 will be initiated by the issue of instructions, which may
be accompanied by a Bid-Offer Acceptance, under BC2 (in accordance with the
Export and Import Limits, QPN, Joint BM Unit Data and Dynamic Parameters which
have been submitted for the day on which the test was called, or in the case of a CCGT
Unit, in accordance with the parameters submitted under OC5.5.1.3(b)).
The
instructions in respect of a CCGT Unit within a CCGT Module will be in respect of the
CCGT Unit, as provided in BC2.
OC5.5.2
User Request For Testing
OC5.5.2.1
Where a User undertakes a test to demonstrate compliance with the Grid Code and
Bilateral Agreement in accordance with CP.6 or CP.7 or CP.8 (other than a failure between
NGET and a User to agree in CP.8.1 where OC5.5.1.1 applies) the User shall request
permission to test using the process laid out in OC7.5.
OC5.5.3
Conduct Of Test
OC5.5.3.1
The performance of the BM Unit will be recorded at Transmission Control Centres notified
by NGET with monitoring at site when necessary, from voltage and current signals provided
by the User for each BM Unit under CC.6.6.1.
OC5.5.3.2
If monitoring at site is undertaken, the performance of the BM Unit will be recorded on a
suitable recorder (with measurements, in the case of a Synchronous Generating Unit,
taken on the Generating Unit Stator Terminals / on the LV side of the generator
transformer) or in the case of a Non-Synchronous Generating Unit (excluding Power Park
Units), Power Park Module or DC Converter at the point of connection (including where
the OTSUA is operational prior to the OTSUA Transfer Time, the Transmission Interface
Point) in the relevant User’s Control Room, in the presence of a reasonable number of
representatives appointed and authorised by NGET. If NGET or the User requests,
monitoring at site will include measurement of the parameters set out in OC5.A.1 or OC5.A.2
as appropriate.
OC5.5.3.3
The User is responsible for carrying out the test and retains the responsibility for the safety
of personnel and plant during the test.
OC5.5.4
Test And Monitoring Assessment
The criteria must be read in conjunction with the full text under the Grid Code reference. The
BM Unit, CCGT Module, Power Park Module or Generating Unit (excluding Power Park
Units) and OTSUA will pass the test the criteria below are met:
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Parameter to be Tested
Criteria against which the test results will be assessed
by NGET.
Harmonic Content
CC.6.1.5(a) Measured harmonic emissions do not
exceed the limits specified in the Bilateral Agreement
or where no such limits are specified, the relevant
planning level specified in G5/4.
Phase Unbalance
CC.6.1.5(b), The measured maximum Phase (Voltage)
Unbalance on the National Electricity Transmission
System should remain, in England and Wales, below
1% and, in Scotland, below 2% and Offshore will be
defined in relevant Bilateral Agreement.
CC.6.1.6 In England and Wales, measured infrequent
short duration peaks in Phase (Voltage) Unbalance
should not exceed the maximum value stated in the
Bilateral Agreement.
CC.6.1.7(a) In England and Wales, measured voltage
fluctuations at the Point of Common Coupling shall
not exceed 1% of the voltage level for step changes.
Measured voltage excursions other than step changes
may be allowed up to a level of 3%. In Scotland,
measured voltage fluctuations at a Point of Common
Coupling shall not exceed the limits set out in
Engineering Recommendation P28.
Flicker
CC.6.1.7(b) Measured voltage fluctuations at a Point of
Common Coupling shall not exceed, for voltages
above 132kV, Flicker Severity (Short Term) of 0.8
Unit and Flicker Severity (Long Term) of 0.6 Unit,
and, for voltages at 132kV and below, shall not exceed
Flicker Severity (Short Term) of 1.0 Unit and Flicker
Severity (Long Term) of 0.8 Unit, as set out in
Engineering Recommendation P28 as current at the
Transfer Date.
Voltage Fluctuation
CC.6.1.8 Offshore, measured voltage fluctuations at
the Point of Common Coupling shall not exceed the
limits set out in the Bilateral Agreement.
Fault Clearance Times
CC.6.2.2.2.2(a), CC.6.2.3.1.1(a), Bilateral Agreement
Back Up Protection
CC.6.2.2.2.2(b), CC.6.2.3.1.1(b) , Bilateral Agreement
Fault Clearance
Voltage Quality
Voltage Fluctuation
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Circuit Breaker Fail
Protection
CC.6.2.2.2.2(c), CC.6.2.3.1.1(c)
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Parameter to be Tested
Reactive Capability
Criteria against which the test results will be assessed
by NGET.
CC.6.3.2 (and in the case of CC.6.3.2(e)(iii), the
Bilateral Agreement), CC.6.3.4, Ancillary Services
Agreement.
For a test initiated under OC.5.5.1.1 the Generating
Unit, DC Converter or Power Park Module or (prior to
the OTSUA Transfer Time) OTSUA will pass the test if
it is within ±5% of the reactive capability registered with
NGET under OC2. the duration of the test will be for a
period of upto 60 minutes during which period the
system voltage at the Grid Entry Point for the relevant
Generating Unit, DC Converter or Power Park
Module or Interface Point in the case of OTSUA will
be maintained by the Generator or DC Converter
Station owner at the voltage specified pursuant to
BC2.8 by adjustment of Reactive Power on the
remaining Generating Unit, DC Converter or Power
Park Modules or OTSUA, if necessary. Any test
performed in respect of an Embedded Medium Power
Station not subject to a Bilateral Agreement or, an
Embedded DC Converter Station not subject to a
Bilateral Agreement shall be as confirmed pursuant to
OC5.8.3.
Measurements of the Reactive Power output under
steady state conditions should be consistent with Grid
Code requirements i.e. fully available within the voltage
range ±5% at 400kV, 275kV and 132kV and lower
voltages.
Governor / Frequency Control
Primary Secondary and
High Frequency
Response
For a test initiated under OC.5.5.1.1 the measured
response in MW/Hz is within ±5% of the level of
response specified in the Ancillary Services
Agreement for that Genset.
Stability with Voltage
CC.6.3.4
Governor / Load /
Frequency Controller
System Compliance
CC.6.3.6(a), CC.6.3.7, CC.6.3.9, CC8.1,
applicable CC.A.3, BC3.5, BC3.6, BC3.7
Output at Reduced
System Frequency
Fast Start
Black Start
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Ancillary Services Agreement, CC.6.3.7 and where
applicable CC.A.3
where
CC.6.3.3 - For variations in System Frequency
exceeding 0.1Hz within a period of less than 10
seconds, the Active Power output is within ±0.2% of
the requirements of CC.6.3.3 when monitored at
prevailing external air temperatures of up to 25ºC.,
BC3.5.1
Ancillary Services Agreement requirements
OC5.7
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Parameter to be Tested
Criteria against which the test results will be assessed
by NGET.
Excitation/Voltage Control CC.6.3.6(b), CC.6.3.8, CC.A.6 or CC.A.7 as applicable,
System
BC2.11.2, Bilateral Agreement
Fault Ride Through
Export and Import
Limits, QPN, Joint BM
Unit Data and Dynamic
Parameters
Synchronisation time
CC.6.3.15, CC.A.4.A or CC.A.4.B as applicable
BC2
The Export and Import Limits, QPN, Joint BM Unit
Data and Dynamic Parameters under test are within
2½% of the declared value being tested.
BC2.5.2.3
Dynamic Parameters
Synchronisation takes place within ±5 minutes of the
time it should have achieved Synchronisation.
Run-up rates
BC2
Achieves the instructed output and, where applicable,
the first and/or second intermediate breakpoints, each
within ±3 minutes of the time it should have reached
such output and breakpoints from Synchronisation (or
break point, as the case may be), calculated from the
run-up rates in its Dynamic Parameters.
Run-down rates
BC2
Achieves the instructed output and, where applicable,
the first and/or second intermediate breakpoints, each
within ±5 minutes of the time it should have reached
such output and breakpoints from Synchronisation (or
break point, as the case may be), calculated from the
run-up rates in its Dynamic Parameters.
OC5.5.4.1
The duration of the Dynamic Parameter tests in the above table will be consistent with and
sufficient to measure the relevant expected input or output derived from the Final Physical
Notification Data and Bid-Offer Acceptances issued under BC2 which are still in dispute
following the procedure in OC5.4.2.
OC5.5.4.2
Due account will be taken of any conditions on the System which may affect the results of
the test. The relevant User must, if requested, demonstrate, to NGET's reasonable
satisfaction, the reliability of the suitable recorders, disclosing calibration records to the
extent appropriate.
OC5.5.5
Test Failure / Re-test
OC5.5.5.1
If the BM Unit, CCGT Modules, Power Park Module, OTSUA, or Generating Unit
(excluding Power Park Units) concerned fails to pass the test instructed by NGET under
OC5.5.1.1 the User must provide NGET with a written report specifying in reasonable detail
the reasons for any failure of the test so far as they are then known to the User after due and
careful enquiry. This must be provided within five Business Days of the test.
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OC5.5.5.2
If in NGETs reasonable opinion the failure to pass the test relates to compliance with the CC
then NGET may invoke the process detailed in CP.8.2 to CP.11.
OC5.5.5.3
If a dispute arises relating to the failure, NGET and the relevant User shall seek to resolve
the dispute by discussion, and, if they fail to reach agreement, the User may by notice
require NGET to carry out a re-test on 48 hours' notice which shall be carried out following
the procedure set out in OC5.5.3 and OC5.5.4 and subject as provided in OC5.5.1.3, as if
NGET had issued an instruction at the time of notice from the User.
OC5.5.6
Dispute Following Re-Test
If the BM Unit, CCGT Module, Power Park Module, OTSUA, or Generating Unit
(excluding Power Park Units) in NGET's view fails to pass the re-test and a dispute arises
on that re-test, either party may use the Disputes Resolution Procedure for a ruling in
relation to the dispute, which ruling shall be binding.
OC5.6
DISPUTE RESOLUTION
OC5.6.1
If following the procedure set out in OC5.5 it is accepted that the BM Unit, CCGT Module,
Power Park Module, OTSUA (prior to the OTSUA Transfer Time) or Generating Unit
(excluding Power Park Units) has failed the test or re-test (as applicable), the User shall
within 14 days, or such longer period as NGET may reasonably agree, following such failure,
submit in writing to NGET for approval the date and time by which the User shall have
brought the BM Unit concerned to a condition where it complies with the relevant
requirement. NGET will not unreasonably withhold or delay its approval of the User’s
proposed date and time submitted. Should NGET not approve the User’s proposed date or
time (or any revised proposal), the User should amend such proposal having regard to any
comments NGET may have made and re-submit it for approval.
OC5.6.2
If a BM Unit fails the test, the User shall submit revised Export and Import Limits, QPN,
Joint BM Unit Data and/or Dynamic Parameters, or in the case of a BM Unit comprising a
Generating Unit, CCGT Module, DC Converter, OTSUA (prior to the OTSUA Transfer
Time) or Power Park Module, the User may amend, with NGET's approval, the relevant
registered parameters of that Generating Unit, CCGT Module, DC Converter, OTSUA
(prior to the OTSUA Transfer Time) or Power Park Module, as the case may be, relating to
the criteria, for the period of time until the BM Unit can achieve the parameters previously
registered, as demonstrated in a re-test.
OC5.6.3
Once the User has indicated to NGET the date and time that the BM Unit, CCGT Module,
Power Park Module, Generating Unit (excluding Power Park Units) or OTSUA (prior to
the OTSUA Transfer Time) can achieve the parameters previously registered or submitted,
NGET shall either accept this information or require the User to demonstrate the restoration
of the capability by means of a repetition of the test referred to in OC5.5.3 by an instruction
requiring the User on 48 hours notice to carry out such a test. The provisions of this OC5.6
will apply to such further test.
OC5.7
BLACK START TESTING
OC5.7.1
General
(a) NGET may require a Generator with a Black Start Station to carry out a test (a "Black
Start Test") on a Genset in a Black Start Station either while the Black Start Station
remains connected to an external alternating current electrical supply (a "BS Unit Test")
or while the Black Start Station is disconnected from all external alternating current
electrical supplies (a "BS Station Test"), in order to demonstrate that a Black Start
Station has a Black Start Capability.
(b) Where NGET requires a Generator with a Black Start Station to carry out a BS Unit
Test, NGET shall not require the Black Start Test to be carried out on more than one
Genset at that Black Start Station at the same time, and would not, in the absence of
exceptional circumstances, expect any of the other Genset at the Black Start Station
to be directly affected by the BS Unit Test.
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(c) NGET may require a Generator with a Black Start Station to carry out a BS Unit Test
at any time (but will not require a BS Unit Test to be carried out more than once in each
calendar year in respect of any particular Genset unless it can justify on reasonable
grounds the necessity for further tests or unless the further test is a re-test, and will not
require a BS Station Test to be carried out more than once in every two calendar years
in respect of any particular Genset unless it can justify on reasonable grounds the
necessity for further tests or unless the further test is a re-test).
(d) When NGET wishes a Generator with a Black Start Station to carry out a Black Start
Test, it shall notify the relevant Generator at least 7 days prior to the time of the Black
Start Test with details of the proposed Black Start Test.
OC5.7.2
Procedure For A Black Start Test
The following procedure will, so far as practicable, be carried out in the following sequence
for Black Start Tests:
OC5.7.2.1
BS Unit Tests
(a) The relevant Generating Unit shall be Synchronised and Loaded;
(b) All the Auxiliary Gas Turbines and/or Auxiliary Diesel Engines in the Black Start
Station in which that Generating Unit is situated, shall be Shutdown.
(c) The Generating Unit shall be De-Loaded and De-Synchronised and all alternating
current electrical supplies to its Auxiliaries shall be disconnected.
(d) The Auxiliary Gas Turbine(s) or Auxiliary Diesel Engine(s) to the relevant
Generating Unit shall be started, and shall re-energise the Unit Board of the relevant
Generating Unit.
(e) The Auxiliaries of the relevant Generating Unit shall be fed by the Auxiliary Gas
Turbine(s) or Auxiliary Diesel Engine(s), via the Unit Board, to enable the relevant
Generating Unit to return to Synchronous Speed.
(f)
OC5.7.2.2
The relevant Generating Unit shall be Synchronised to the System but not Loaded,
unless the appropriate instruction has been given by NGET under BC2.
BS Station Test
(a) All Generating Units at the Black Start Station, other than the Generating Unit on
which the Black Start Test is to be carried out, and all the Auxiliary Gas Turbines
and/or Auxiliary Diesel Engines at the Black Start Station, shall be Shutdown.
(b) The relevant Generating Unit shall be Synchronised and Loaded.
(c) The relevant Generating Unit shall be De-Loaded and De-Synchronised.
(d) All external alternating current electrical supplies to the Unit Board of the relevant
Generating Unit, and to the Station Board of the relevant Black Start Station, shall
be disconnected.
(e) An Auxiliary Gas Turbine or Auxiliary Diesel Engine at the Black Start Station shall
be started, and shall re-energise either directly, or via the Station Board, the Unit
Board of the relevant Generating Unit.
(f)
The provisions of OC5.7.2.1 (e) and (f) shall thereafter be followed.
OC5.7.2.3
All Black Start Tests shall be carried out at the time specified by NGET in the notice given
under OC5.7.1(d) and shall be undertaken in the presence of a reasonable number of
representatives appointed and authorised by NGET, who shall be given access to all
information relevant to the Black Start Test.
OC5.7.2.4
Failure of a Black Start Test
A Black Start Station shall fail a Black Start Test if the Black Start Test shows that it does
not have a Black Start Capability (ie. if the relevant Generating Unit fails to be
Synchronised to the System within two hours of the Auxiliary Gas Turbine(s) or Auxiliary
Diesel Engine(s) being required to start).
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OC5.7.2.5
If a Black Start Station fails to pass a Black Start Test the Generator must provide NGET
with a written report specifying in reasonable detail the reasons for any failure of the test so
far as they are then known to the Generator after due and careful enquiry. This must be
provided within five Business Days of the test. If a dispute arises relating to the failure,
NGET and the relevant Generator shall seek to resolve the dispute by discussion, and if
they fail to reach agreement, the Generator may require NGET to carry out a further Black
Start Test on 48 hours notice which shall be carried out following the procedure set out in
OC5.7.2.1 or OC5.7.2.2 as the case may be, as if NGET had issued an instruction at the
time of notice from the Generator.
OC5.7.2.6
If the Black Start Station concerned fails to pass the re-test and a dispute arises on that retest, either party may use the Disputes Resolution Procedure for a ruling in relation to the
dispute, which ruling shall be binding.
OC5.7.2.7
If following the procedure in OC5.7.2.5 and OC5.7.2.6 it is accepted that the Black Start
Station has failed the Black Start Test (or a re-test carried out under OC5.7.2.5), within 14
days, or such longer period as NGET may reasonably agree, following such failure, the
relevant Generator shall submit to NGET in writing for approval, the date and time by which
that Generator shall have brought that Black Start Station to a condition where it has a
Black Start Capability and would pass the Black Start Test, and NGET will not
unreasonably withhold or delay its approval of the Generator's proposed date and time
submitted. Should NGET not approve the Generator's proposed date and time (or any
revised proposal) the Generator shall revise such proposal having regard to any comments
NGET may have made and resubmit it for approval.
OC5.7.2.8
Once the Generator has indicated to NGET that the Generating Station has a Black Start
Capability, NGET shall either accept this information or require the Generator to
demonstrate that the relevant Black Start Station has its Black Start Capability restored,
by means of a repetition of the Black Start Test referred to in OC5.7.1(d) following the same
procedure as for the initial Black Start Test. The provisions of this OC5.7.2 will apply to
such test.
OC5.8
PROCEDURES APPLYING TO EMBEDDED MEDIUM POWER STATION NOT SUBJECT
TO A BILATERAL AGREEMENT AND EMBEDDED DC CONVERTER STATIONS NOT
SUBJECT TO A BILATERAL AGREEMENT
OC5.8.1
Compliance Statement
Each Network Operator shall ensure that each Embedded Person provides to the
Network Operator upon NGET's request:
(a) written confirmation that each such Generating Unit, Power Park Module or DC
Converter complies with the requirements of the CC; and
(b) evidence, where requested, reasonably satisfactory to NGET, of such compliance.
Such a request shall not normally be made by NGET more than twice in any calendar
year in respect of any Generator’s Generating Unit or Power Park Module or DC
Converter owner's DC Converter.
The Network Operator shall provide the evidence or written confirmation required under
OC5.8.1 (a) and (b) forthwith upon receipt to NGET.
OC5.8.2
Network Operator’s Obligations To Facilitate Tests
If:
(a) the Network Operator fails to procure the confirmation referred to at OC5.8.1(a); or
(b) the evidence of compliance is not to NGET’s reasonable satisfaction,
then, NGET shall be entitled to require the Network Operator to procure access upon terms
reasonably satisfactory to NGET to enable NGET to witness the Embedded Person
carrying out the tests referred to in OC5.8.3 in respect of the relevant Embedded Medium
Power Station or Embedded DC Converter Station.
OC5.8.3
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NGET may, in accordance with the provisions of OC5.8.2, at any time (although not normally
more than twice in any calendar year in respect of any particular Embedded Medium Power
Station not subject to a Bilateral Agreement or Embedded DC Converter Station not
subject to a Bilateral Agreement) issue an instruction requiring the Network Operator
within whose System the relevant Medium Power Station not subject to a Bilateral
Agreement or DC Converter Station not subject to a Bilateral Agreement is Embedded,
to require the Embedded Person to carry out a test.
Such test shall be carried out at a time no sooner than 48 hours from the time that the
instruction was issued, on any one or more of the Generating Units, Power Park Module or
DC Converter comprising part of the relevant Embedded Medium Power Station or
Embedded DC Converter Station and should only be to demonstrate that:
(a) the relevant Generating Unit, Power Park Module or DC Converter meets the
requirements of the paragraphs in the CC which are applicable to such Generating
Units, Power Park Module or DC Converter;
(b) the Reactive Power capability registered with NGET under OC2 meets the
requirements set out in CC.6.3.2.
The instruction may only be issued where, following consultation with the relevant Network
Operator, NGET has:
(a) confirmed to the relevant Network Operator the manner in which the test will be
conducted, which shall be consistent with the principles established in OC5.5.3; and
(b) received confirmation from the relevant Network Operator that the relevant
Generating Unit, Power Park Module or DC Converter would not then be unavailable
by reason of forced outage or Planned Outage expected prior to the instruction.
The relevant Network Operator is responsible for ensuring the performance of any test so
required by NGET and the Network Operator shall ensure that the Embedded Person
retains the responsibility for ensuring the safety of personnel and plant during the test.
OC5.8.4
Test Failures/Re-Tests And Disputes
The relevant Network Operator shall:
(a) ensure that provisions equivalent to OC5.5.5, OC5.5.6 and OC5.6 apply to Embedded
Medium Power Stations not the subject of a Bilateral Agreement or Embedded DC
Converter Stations not the subject of a Bilateral Agreement within its System in
respect of test failures, re-tests and disputes as to test failures and re-tests;
(b) ensure that the provisions equivalent to OC5.5.5, OC5.5.6 and OC5.6 referred to in
OC5.8.4(a) are effective so that NGET may require, if it so wishes, the provision to it of
any reports or other information equivalent to those or that to which NGET would be
entitled in relation to test failures, re-tests and disputes as to test failures and re-tests
under the provisions of OC5.5.5, OC5.5.6 and OC5.6; and
(c) the provisions equivalent to OC5.5.5, OC5.5.6 and OC5.6 referred to in OC5.8.4(a) are
effective to permit NGET to conduct itself and take decisions in such a manner in
relation to test failures, re-tests and disputes as to test failures and re-tests in respect of
Embedded Medium Power Stations not the subject of a Bilateral Agreement or
Embedded DC Converter Stations not the subject of a Bilateral Agreement as it is
able to conduct itself and take decisions in relation to test failures, re-tests and disputes
as to test failures and re-tests under OC5.5.5, OC5.5.6 and OC5.6.
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APPENDIX 1 - ONSITE SIGNAL PROVISION FOR WITNESSING TESTS
OC5.A.1.1
During any tests witnessed on-site by NGET, the following signals shall be provided to
NGET by the Generator, Generator undertaking OTSDUW or DC Converter Station owner
in accordance with CC.6.6.2:
OC5.A.1.2
Synchronous Generating Units
(a) All Tests

MW - Active Power at Generating Unit terminals
(b) Reactive &
Excitation System

MVAr - Reactive Power at Generating Unit terminals

Vt - Generating Unit terminal voltage

Efd- Generating Unit field voltage and/or main exciter field
voltage

Ifd – Generating Unit field current (where possible)

Power System Stabiliser output, where applicable.

Noise – Injected noise signal (where applicable and
possible)

Fsys - System Frequency

Finj - Injected Speed Reference

Logic - Stop / Start Logic Signal
(c) Governor System &
Frequency Response
For Gas Turbines:

GT Fuel Demand

GT Fuel Valve Position

GT Inlet Guide Vane Position

GT Exhaust Gas Temperature
For Steam Turbines at >= 1Hz:

Pressure before Turbine Governor Valves

Turbine Governor Valve Positions

Governor Oil Pressure*

Boiler Pressure Set Point *

Superheater Outlet Pressure *

Pressure after Turbine Governor Valves*

Boiler Firing Demand*
*Where applicable (typically not in CCGT module)
For Hydro Plant:
(d) Compliance with
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
Speed Governor Demand Signal

Actuator Output Signal

Guide Vane / Needle Valve Position

Fsys - System Frequency
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CC.6.3.3
OC5.A.1.3

Finj - Injected Speed Reference

Appropriate control system parameters as agreed with
NGET (See OC5.A.2.9)
Power Park Modules, OTSUA and DC Converters
Each Power Park Module and DC Converters at Grid Entry
Point or User System Entry Point
(a) Real Time on
site.
(b) Real Time on site
or Downloadable
(c) Real Time on site
or Downloadable

Total Active Power (MW)

Total Reactive Power (MVAr)

Line-line Voltage (kV)

System Frequency (Hz)

Injected frequency signal (Hz) or test logic signal (Boolean)
when appropriate

Injected voltage signal (per unit voltage) or test logic signal
(Boolean) when appropriate

In the case of an Onshore Power Park Module the
Onshore Power Park Module site voltage (MV) (kV)

Power System Stabiliser output, where appropriate

In the case of a Power Park Module or DC Converter
where the Reactive Power is provided by from more than
one Reactive Power source, the individual Reactive Power
contributions from each source, as agreed with NGET.

In the case of DC Converters appropriate control system
parameters as agreed with NGET (See OC5.A.4)

In the case of an Offshore Power Park Module the Total
Active Power (MW) and the Total Reactive Power (MVAr)
at the Offshore Grid Entry Point

Available power for Power Park Module (MW)

Power source speed for Power Park Module (e.g. wind
speed) (m/s) when appropriate

Power source direction for Power Park Module (degrees)
when appropriate
See OC5.A.1.3.1
OC5.A.1.3.1
NGET accept that the signals specified in OC5.A.1.3(c) may have lower effective sample
rates than those required in CC.6.6.2 although any signals supplied for connection to
NGET’s recording equipment which do not meet at least the sample rates detailed in
CC.6.6.2 should have the actual sample rates indicated to NGET before testing commences.
OC5.A.1.3.2
For all NGET witnessed testing either;
Issue 5 Revision 15
(i)
the Generator or DC Converter Station owner shall provide to NGET all signals
outlined in OC5.A.1.3 direct from the Power Park Module control system without any
attenuation, delay or filtering which would result in the inability to fully demonstrate the
objectives of the test, or identify any potential safety or plant instability issues, and with
a signal update rate corresponding to CC.6.6.2.1; or
(ii)
in the case of Onshore Power Park Modules the Generator or DC Converter Station
owner shall provide signals OC5.A.1.3(a) direct from one or more transducer(s)
connected to current and voltage transformers for monitoring in real time on site; or,
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(iii) In the case of Offshore Power Park Modules and OTSUA signals OC5.A.1.3(a) will be
provided at the Interface Point by the Offshore Transmission Licensee pursuant to
the STC or by the Generator when OTSDUW Arrangements apply.
OC5.A.1.3.3
Options OC5.A.1.3.2 (ii) and (iii) will only be available on condition that;
(a) all signals outlined in OC5.A.1.3 are recorded and made available to NGET by the
Generator or DC Converter Station owner from the Power Park Module or OTSUA or
DC Converter control systems as a download once the testing has been completed;
and
(b) the full test results are provided by the Generator or DC Converter Station owner
within 2 working days of the test date to NGET unless NGET agrees otherwise; and
(c) all data is provided with a sample rate in accordance with CC.6.6.2.2 unless NGET
agrees otherwise; and
(d) in NGET’s reasonable opinion the solution does not unreasonably add a significant
delay between tests or impede the volume of testing which can take place on the day.
OC5.A.1.3.4
In the case of where transducers connected to current and voltage transformers are installed
(OC5.A.1.3.3 (ii) and (iii)), the transducers shall meet the following specification
(a) The transducer(s) shall be permanently installed to easily allow safe testing at any point
in the future, and to avoid a requirement for recalibration of the current transformers and
voltage transformers.
(b) The transducer(s) should be directly connected to the metering quality current
transformers and voltage transformers or similar.
(c) The transducers shall either have a response time no greater than 50ms to reach 90%
of output, or no greater than 300ms to reach 99.5%.
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APPENDIX 2 - COMPLIANCE TESTING OF SYNCHRONOUS PLANT
OC5.A.2.1
Scope
OC5.A.2.1.1
This Appendix sets out the tests contained therein to demonstrate compliance with the
relevant clauses of the Connection Conditions of the Grid Code. This Appendix shall be
read in conjunction with the CP with regard to the submission of the reports to NGET.
OC5.A.2.1.2
The tests specified in this Appendix will normally be sufficient to demonstrate compliance
however NGET may:
(i)
agree an alternative set of tests provided NGET deem the alternative set of tests
sufficient to demonstrate compliance with the Grid Code and Bilateral Agreement;
and/or
(ii)
require additional or alternative tests if information supplied to NGET during the
compliance process suggests that the tests in this Appendix will not fully demonstrate
compliance with the relevant section of the Grid Code or Bilateral Agreement.
(iii) Agree a reduced set of tests for subsequent Generating Units following successful
completion of the first Generating Unit tests in the case of a Power Station comprised
of two or more Generating Units which NGET reasonably considers to be identical.
If:
(a) the tests performed pursuant to OC5.A.2.1.2(iii) in respect of subsequent Generating
Units do not replicate the full tests for the first Generating Unit, or
(b) any of the tests performed pursuant to OC5.A.2.1.2(iii) do not fully demonstrate
compliance with the relevant aspects of the Grid Code, Ancillary Services Agreement
and / or Bilateral Agreement,
then notwithstanding the provisions above, the full testing requirements set out in
Appendix will be applied.
this
OC5.A.2.1.3
The Generator is responsible for carrying out the tests set out in and in accordance with this
Appendix and the Generator retains the responsibility for the safety of personnel and plant
during the test. NGET will witness all of the tests outlined or agreed in relation to this
Appendix unless NGET decides and notifies the Generator otherwise. Reactive Capability
tests may be witnessed by NGET remotely from the NGET control centre. For all on site
NGET witnessed tests the Generator should ensure suitable representatives from the
Generator and manufacturer (if appropriate) are available on site for the entire testing
period. In all cases the Generator shall provide suitable monitoring equipment to record all
relevant test signals as outlined below in OC5.A.3.1.5.
OC5.A.2.1.6
The Generator shall submit a schedule of tests to NGET in accordance with CP.4.3.1
OC5.A.2.1.7
Prior to the testing of a Generating Unit the Generator shall complete the Integral
Equipment Test procedure in accordance with OC.7.5
OC5.A.2.1.8
Full Generating Unit testing as required by CP.7.2 is to be completed as defined in
OC5.A.2.2 through to OC5.A.2.9
OC5.A.2.2
Excitation System Open Circuit Step Response Tests
OC5.A.2.2.1
The open circuit step response of the Excitation System will be tested by applying a voltage
step change from 90% to 100% of the nominal Generating Unit terminal voltage, with the
Generating Unit on open circuit and at rated speed.
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OC5.A.2.2.1
The test shall be carried out prior to synchronisation in accordance with CP.6.4. This is not
witnessed by NGET unless specifically requested by NGET. Where NGET is not witnessing
the tests, the Generator shall supply the recordings of the following signals to NGET in an
electronic spreadsheet format:
Vt - Generating Unit terminal voltage
Efd - Generating Unit field voltage or main exciter field voltage
Ifd- Generating Unit field current (where possible)
Step injection signal
OC5.A.2.2.3
Results shall be legible, identifiable by labelling, and shall have appropriate scaling.
OC5.A.2.3
Open & Short Circuit Saturation Characteristics
OC5.A.2.3.1
The test shall normally be carried out prior to synchronisation in accordance with CP.6.4.
Manufacturer factory test results may be used where appropriate or manufacturers factory
type test results may be used if agreed by NGET.
OC5.A.2.3.2
This is not witnessed by NGET. Graphical and tabular representations of the results in an
electronic spreadsheet format showing per unit open circuit terminal voltage and short circuit
current versus per unit field current shall be submitted to NGET.
OC5.A.2.3.3
Results shall be legible, identifiable by labelling, and shall have appropriate scaling.
OC5.A.2.4
Excitation System On-Load Tests
OC5.A.2.4.1
The time domain performance of the Excitation System shall be tested by application of
voltage step changes corresponding to 1% and 2% of the nominal terminal voltage.
OC5.A.2.4.2
Where a Power System Stabiliser is present:
(i)
The PSS must only be commissioned in accordance with BC2.11.2. When a PSS is
switched on for the first time as part of on-load commissioning or if parameters have
been adjusted the Generator should consider reducing the PSS output gain by at least
50% and should consider reducing the limits on PSS output by at least a factor of 5 to
prevent unexpected PSS action affecting the stability of the Generating Unit or the
National Electricity Transmission System.
(ii)
The time domain performance of the Excitation System shall be tested by application
of voltage step changes corresponding to 1% and 2% of the nominal terminal voltage,
repeating with and without the PSS in service.
(iii) The frequency domain tuning of the PSS shall also be demonstrated by injecting a
0.2Hz-3Hz band limited random noise signal into the Automatic Voltage Regulator
reference with the Generating Unit operating at points specified by NGET (up to rated
MVA output).
(iv) The PSS gain margin shall be tested by increasing the PSS gain gradually to threefold
and observing the Generating Unit steady state Active Power output.
(v) The interaction of the PSS with changes in Active Power shall be tested by application
of a +0.5Hz frequency injection to the governor while the Generating Unit is selected to
Frequency Sensitive Mode.
(vi) If the Generating Unit is of the pump storage type then the step tests shall be carried
out, with and without the PSS, in the pumping mode in addition to the generating mode.
(vii) Where the Bilateral Agreement requires that the PSS is in service at a specified
loading level additional testing witnessed by NGET will be required during the
commissioning process before the Generating Unit or CCGT Module may exceed this
output level.
(viii) Where the Excitation System includes a PSS, the Generator shall provide a suitable
noise source to facilitate noise injection testing.
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OC5.A.2.4.3
The following typical procedure is provided to assist Generators in drawing up their own site
specific procedures for the NGET witnessed PSS Tests.
Test
Injection
Notes
Synchronous Generator running rated MW, unity
pf, PSS Switched Off
1
2
3

Record steady state for 10 seconds

Inject +1% step to AVR Voltage Reference and
hold for at least 10 seconds until stabilised

Remove step returning AVR Voltage Reference
to nominal and hold for at least 10 seconds

Record steady state for 10 seconds

Inject +2% step to AVR Voltage Reference and
hold for at least 10 seconds until stabilised

Remove step returning AVR Voltage Reference
to nominal and hold for at least 10 seconds

Inject band limited (0.2-3Hz) random noise
signal into voltage reference and measure
frequency spectrum of Real Power.

Remove noise injection.
Switch On Power System Stabiliser
4
5
6
7
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
Record steady state for 10 seconds

Inject +1% step to AVR Voltage Reference and
hold for at least 10 seconds until stabilised

Remove step returning AVR Voltage Reference
to nominal and hold for at least 10 seconds

Record steady state for 10 seconds

Inject +2% step to AVR Voltage Reference and
hold for at least 10 seconds until stabilised

Remove step returning AVR Voltage Reference
to nominal and hold for at least 10 seconds

Increase PSS gain at 30 second intervals. i.e.
x1 – x1.5 – x2 – x2.5 – x3

Return PSS gain to initial setting

Inject band limited (0.2-3Hz) random noise
signal into voltage reference and measure
frequency spectrum of Real Power.

Remove noise injection.
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8

Select the governor to FSM

Inject +0.5 Hz step into governor.

Hold until generator MW output is stabilised

Remove step
OC5.A.2.5
Under-excitation Limiter Performance Test
OC5.A.2.5.1
Initially the performance of the Under-excitation Limiter should be checked by moving the
limit line close to the operating point of the Generating Unit when operating close to unity
power factor. The operating point of the Generating Unit is then stepped into the limit by
applying a 2% decrease in Automatic Voltage Regulator reference voltage.
OC5.A.2.5.2
The final performance of the Under-excitation Limiter shall be demonstrated by testing its
response to a step change corresponding to a 2% decrease in Automatic Voltage
Regulator reference voltage when the Generating Unit is operating just off the limit line, at
the designed setting as indicated on the Performance Chart submitted to NGET under
OC2.
OC5.A.2.5.3
Where possible the Under-excitation Limiter should also be tested by operating the tapchanger when the Generating Unit is operating just off the limit line, as set up.
OC5.A.2.5.4
The Under-excitation Limiter will normally be tested at low Active Power output and at
maximum Active Power output (Registered Capacity).
OC5.A.2.5.5
The following typical procedure is provided to assist Generators in drawing up their own site
specific procedures for the NGET witnessed Under-excitation Limiter Tests.
Test
Injection
Notes
Synchronous generator running rated MW at
unity power factor.
Under-excitation limit
temporarily moved close to the operating point
of the generator.
1

PSS on.

Inject -2% voltage step into AVR voltage
reference and hold at least for 10 seconds
until stabilised

Remove step returning AVR Voltage
Reference to nominal and hold for at least 10
seconds
Under-excitation limit moved to normal position.
Synchronous generator running at rated MW
and at leading MVArs close to Under-excitation
limit.
2
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
PSS on.

Inject -2% voltage step into AVR voltage
reference and hold at least for 10 seconds
until stabilised

Remove step returning AVR Voltage
Reference to nominal and hold for at least 10
seconds
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OC5.A.2.6
Over-excitation Limiter Performance Test
Description & Purpose of Test
OC5.A.2.6.1
The performance of the Over-excitation Limiter, where it exists, shall be demonstrated by
testing its response to a step increase in the Automatic Voltage Regulator reference
voltage that results in operation of the Over-excitation Limiter. Prior to application of the
step the Generating Unit shall be generating Rated Active Power and operating within its
continuous Reactive Power capability. The size of the step will be determined by the
minimum value necessary to operate the Over-excitation Limiter and will be agreed by
NGET and the Generator. The resulting operation beyond the Over-excitation Limit shall
be controlled by the Over-excitation Limiter without the operation of any protection that
could trip the Generating Unit. The step shall be removed immediately on completion of the
test.
OC5.A.2.6.2
If the Over-excitation Limiter has multiple levels to account for heating effects, an
explanation of this functionality will be necessary and if appropriate, a description of how this
can be tested.
OC5.A.2.6.3
The following typical procedure is provided to assist Generators in drawing up their own site
specific procedures for the NGET witnessed Under-excitation Limiter Tests.
Test
Injection
Notes
Synchronous Generator running rated MW and
maximum lagging MVAr.
Over-excitation Limit temporarily set close to this
operating point. PSS on.
1

Inject positive voltage step into AVR voltage
reference and hold

Wait till Over-excitation Limiter operates after
sufficient time delay to bring back the
excitation back to the limit.

Remove step returning
Reference to nominal.
AVR
Voltage
Over-excitation Limit restored to its normal
operating value. PSS on.
OC5.A.2.7
Reactive Capability
OC5.A.2.7.1
The leading and lagging Reactive Power capability on each Generating Unit will normally
be demonstrated by operation of the Generating Unit at 0.85 power factor lagging for 1 hour
and 0.95 power factor leading for 1 hour.
OC5.A.2.7.2
In the case of an Embedded Generating Unit where distribution network considerations
restrict the Generating Unit Reactive Power Output then the maximum leading and lagging
capability will be demonstrated without breaching the host network operators limits.
OC5.A.2.7.3
The test procedure, time and date will be agreed with NGET and will be to the instruction of
NGET control centre and shall be monitored and recorded at both the NGET control centre
and by the Generator.
OC5.A.2.7.4
Where the Generator is recording the voltage and Reactive Power at the Generating Unit
terminals the results shall be supplied in an electronic spreadsheet format.
OC5.A.2.7.5
The ability of the Generating Unit to comply with the operational requirements specified in
BC2.A.2.6 and CC.6.1.7 will normally be demonstrated by changing the tap position and,
where agreed in the Bilateral Agreement, the Generating Unit terminal voltage.
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OC5.A.2.8 Governor and Load Controller Response Performance
OC5.A.2.8.1
The governor and load controller response performance will be tested by injecting simulated
frequency deviations into the governor and load controller systems. Such simulated
frequency deviation signals must be injected simultaneously at both speed governor and
load controller references. For CCGT modules, simultaneous injection into all gas turbines,
steam turbine governors and module controllers is required.
OC5.A.2.8.2
Prior to witnessing the governor tests set out in OC5.A.2.8.6, NGET requires the Generator
to conduct the preliminary tests detailed in OC5.A.2.8.4 and send the results to NGET for
assessment unless agreed otherwise by NGET. The results should be supplied in an
electronic spreadsheet format. These tests shall be completed at least two weeks prior to the
witnessed governor response tests.
OC5.A.2.8.3
Where CCGT module or Generating Unit is capable of operating on alternative fuels, tests
will be required to demonstrate performance when operating on each fuel. NGET may agree
a reduction from the tests listed in OC5.A.2.8.6 for demonstrating performance on the
alternative fuel. This includes the case where a main fuel is supplemented by bio-fuel.
Preliminary Governor Frequency Response Testing
OC5.A.2.8.4
Prior to conducting the full set of tests as per OC5.A.2.8.6, Generators are required to
conduct a preliminary set of tests below to confirm the frequency injection method is correct
and the plant control performance is within expectation. The test numbers refer to Figure 1
below. With the plant running at 80% of full load, the following frequency injections shall be
applied.
Test No
(Figure 1)
8
14
13
OC5.A.2.8.5
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Frequency Injection

Inject - 0.5Hz frequency fall over 10 sec

Hold until conditions stabilise

Remove the injected signal

Inject +0.5Hz frequency rise over 10 sec

Hold until conditions stabilise

Remove the injected signal

Inject -0.5Hz frequency fall over 10 sec

Hold for a further 20 sec

At 30 sec from the start of the test, Inject
a +0.3Hz frequency rise over 30 sec.

Hold until conditions stabilise

Remove the injected signal
Notes
The recorded results (e.g. Finj, MW and control signals) should be sampled at a minimum
rate of 1 Hz to allow NGET to assess the plant performance from the initial transients
(seconds) to the final steady state conditions (5-15 minutes depending on the plant design).
This is not witnessed by NGET. The Generator shall supply the recordings including data to
NGET in an electronic spreadsheet format. Results shall be legible, identifiable by labelling,
and shall have appropriate scaling.
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Full Frequency Response Testing Schedule Witnessed by NGET
OC5.A.2.8.6
The tests are to be conducted at a number of different Module Load Points (MLP). The load
points are conducted as shown below unless agreed otherwise by NGET.
Module Load Point 6
(Maximum Export Limit)
100% MEL
Module Load Point 5
95% MEL
Module Load Point 4
(Mid point of Operating Range)
80% MEL
Module Load Point 3
70% MEL
Module Load Point 2
(Minimum Generation)
MG
Module Load Point 1
(Design Minimum Operating Level)
OC5.A.2.8.7
OC5.A.2.8.8
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DMOL
The tests are divided into the following two types;
(i)
Frequency response volume tests as per OC5.A.2.8. Figure 1. These tests consist of
Frequency profile and ramp tests.
(ii)
System islanding and step response tests as shown by OC5.A.2.8. Figure 2.
There should be sufficient time allowed between tests for control systems to reach steady
state. Where the diagram states ‘HOLD’ the current injection should be maintained until the
Active Power (MW) output of the Generating Unit or CCGT Module has stabilised. The
frequency response capability test (see Figure 1) injection signal shall be returned to zero at
the same rate at which it was applied. NGET may require repeat tests should the tests give
unexpected results.
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0.6
HOLD
0.4
Frequency (Hz)
HOLD
0.2
HOLD
0 10s 30s
60s
10s
10s
10s
10s
10s
0 10s 30s
60s
10s
HOLD
HOLD
HOLD
-0.2
-0.4
HOLD
-0.6
HOLD
0
-0.8
Typical
Response (MW)
+
0
_
Load
Point
LF Event
Profile 1
LF Ramp
-0.1Hz
HF Ramp
+0.1Hz
LF Ramp
-0.2Hz
HF Ramp
+0.2Hz
LF Ramp
-0.5Hz
HF Ramp
+0.5Hz
LF Event
Profile 2
MLP6
*
*
1
2
3
*
4
*
MLP5
5
*
*
6
*
*
7
*
MLP4
8
9
10
11
12
13
14
*
MLP3
15
*
*
*
*
*
16
17
MLP2
18
*
*
19
20
21
*
22
MLP1
23
*
*
24
25
*
*
26
Figure 1: Frequency Response Capability Tests
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HOLD
0.8
*
HOLD
0.6
HOLD
HOLD
0.2
0
0 1s
-0.2
HOLD
0 1s (G) 31s
0 2s (A,J) 32s
HOLD
Frequency (Hz)
0.4
0 30s
HOLD
-0.4
HOLD
-0.6
HOLD
-0.5Hz (K)
-2Hz (A,J)
-0.8
Typical
Response (MW)
+
0
_
Load Point +2.0*
+0.02
-0.2
+0.2
-0.5
+0.5
+0.6
MLP6
BC1
BC2
MLP6 LFSM
BC3
BC4
MLP5
-0.5 -2.0
+ 0**
L
A
MLP4
D/E
F
G
H
I
J
M
*
MLP4 LFSM
N
MLP3
MLP2
MLP1
K
Figure 2: System islanding and step response tests
* This will generally be +2.0Hz unless an injection of this size causes a reduction in plant
output that takes the operating point below Designed Minimum Operating Level in which
case an appropriate injection should be calculated in accordance with the following:
For example 0.9Hz is needed to take an initial output 65% to a final output of 20%. If the
initial output was not 65% and the Designed Minimum Operating Level is not 20% then the
injected step should be adjusted accordingly as shown in the example given below
Initial Output
65%
Designed Minimum Operating Level
20%
Frequency Controller Droop
4%
Frequency to be injected =
(0.65 - 0.20) x 0.04 x 50 = 0.9Hz
** Tests L and M in Figure 2 shall be conducted if in this range of tests the system frequency
feedback signal is replaced by the injection signal rather than the injection signal being
added to the system frequency signal. The tests will consist of monitoring the Generating
Unit and CCGT Module in Frequency Sensitive Mode during normal system frequency
variations without applying any injection. Test N in figure 2 shall be conducted in all cases.
All three tests should be conducted for a period of at least 10 minutes.
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OC5.A.2.9
Compliance with CC.6.3.3 Functionality Test
OC5.A.2.9.1
Where the plant design includes active control function or functions to deliver CC.6.3.3
compliance, the Generator will propose and agree a test procedure with NGET, which will
demonstrate how the Generating Unit Active Power output responds to changes in
System Frequency and ambient conditions (e.g. by Frequency and temperature injection
methods).
OC5.A.2.9.2
The Generator shall inform NGET if any load limiter control is additionally employed.
OC5.A.2.9.3
With reference to the signals specified in OC5.A.1, NGET will agree with the Generator
which additional control system parameters shall be monitored to demonstrate the
functionality of CC.6.3.3 compliance systems. Where NGET recording equipment is not used
results shall be supplied to NGET in an electronic spreadsheet format.
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APPENDIX 3 - COMPLIANCE TESTING OF POWER PARK MODULES
(AND OTSUA)
OC5.A.3.1
Scope
OC5.A.3.1.1
This Appendix outlines the general testing requirements for Power Park Modules and
OTSUA to demonstrate compliance with the relevant aspects of the Grid Code, Ancillary
Services Agreement and Bilateral Agreement. The tests specified in this Appendix will
normally be sufficient to demonstrate compliance however NGET may:
(i)
agree an alternative set of tests provided NGET deem the alternative set of tests
sufficient to demonstrate compliance with the Grid Code, Ancillary Services
Agreement and Bilateral Agreement; and/or
(ii)
require additional or alternative tests if information supplied to NGET during the
compliance process suggests that the tests in this Appendix will not fully demonstrate
compliance with the relevant section of the Grid Code, Ancillary Services Agreement
or Bilateral Agreement; and/or
(ii)
require additional tests if a Power System Stabiliser is fitted; and/or
(iv) agree a reduced set of tests if a relevant Manufacturer's Data & Performance Report
has been submitted to and deemed to be appropriate by NGET; and/or
(v) agree a reduced set of tests for subsequent Power Park Modules or OTSUA following
successful completion of the first Power Park Module or OTSUA tests in the case of a
Power Station comprised of two or more Power Park Modules or OTSUA which
NGET reasonably considers to be identical.
If:
(a) the tests performed pursuant to OC5.A.3.1.1(iv) do not replicate the results contained in
the Manufacturer’s Data & Performance Report or
(b) the tests performed pursuant to OC5.A.3.1.1(v) in respect of subsequent Power Park
Modules or OTSUA do not replicate the full tests for the first Power Park Module or
OTSUA, or
(c) any of the tests performed pursuant to OC5.A.3.1.1(iv) or OC5.A.3.1.1(v) do not fully
demonstrate compliance with the relevant aspects of the Grid Code, Ancillary
Services Agreement and / or Bilateral Agreement,
then notwithstanding the provisions above, the full testing requirements set out in
Appendix will be applied.
this
OC5.A.3.1.2
The Generator is responsible for carrying out the tests set out in and in accordance with this
Appendix and the Generator retains the responsibility for the safety of personnel and plant
during the test. NGET will witness all of the tests outlined or agreed in relation to this
Appendix unless NGET decides and notifies the Generator owner otherwise. Reactive
Capability tests may be witnessed by NGET remotely from the NGET control centre. For all
on site NGET witnessed tests the Generator must ensure suitable representatives from the
Generator and / or Power Park Module manufacturer (if appropriate) and/or OTSUA
manufacturer (if appropriate) are available on site for the entire testing period. In all cases
and in addition to any recording of signals conducted by NGET the Generator shall record
all relevant test signals as outlined in OC5.A.1.
OC5.A.3.1.3
In addition to the dynamic signals supplied in OC5.A.1 the Generator shall inform NGET of
the following information prior to the commencement of the tests and any changes to the
following, if any values change during the tests:
OC5.A.3.1.4
Issue 5 Revision 15
(i)
All relevant transformer tap numbers; and
(ii)
Number of Power Park Units in operation
The Generator shall submit a detailed schedule of tests to NGET in accordance with
CP.6.3.1, and this Appendix.
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OC5.A.3.1.5
Prior to the testing of a Power Park Module or OTSUA the Generator shall complete the
Integral Equipment Tests procedure in accordance with OC.7.5.
OC5.A.3.1.6
Partial Power Park Module or OTSUA testing as defined in OC5.A.3.2 and OC5.A.3.3 is to
be completed at the appropriate stage in accordance with CP.6.
OC5.A.3.1.7
Full Power Park Module or OTSUA testing as required by CP.7.2 is to be completed as
defined in OC5.A.3.4 through to OC5.A.3.7.
OC5.A.3.1.8
Where OTSDUW Arrangements apply and prior to the OTSUA Transfer Time any relevant
OTSDUW Plant and Apparatus shall be considered within the scope of testing described in
this Appendix. Performance shall be assessed against the relevant Grid Code requirements
for OTSDUW Plant and Apparatus at the Interface Point and other Generator Plant and
Apparatus at the Offshore Grid Entry Point. This Appendix should be read accordingly.
OC5.A.3.2
Pre 20% (or <50MW) Synchronised Power Park Module Basic Voltage Control Tests
OC5.A.3.2.1
Before 20% of the Power Park Module (or 50MW if less) has commissioned, either voltage
control test OC5.A.3.5.6(i) or (ii) must be completed in accordance with CP.6.
OC5.A.3.2.2
In the case of an Offshore Power Park Module which provides all or a portion of the
Reactive Power capability as described in CC.6.3.2(e)(iii) and / or voltage control
requirements as described in CC.6.3.8(b)(ii) to enable an Offshore Transmission Licensee
to meet the requirements of STC Section K, the Generator is required to cooperate with the
Offshore Transmission Licensee to conduct the 20% voltage control test. The results in
relation to the Offshore Power Park Module will be assessed against the requirements in
the Bilateral Agreement. In the case of OTSUA prior to the OTSUA Transfer Time, the
Generator shall conduct the testing by reference to the entire control system responding to
changes at the Interface Point.
OC5.A.3.3
For Power Park Modules with Registered Capacity ≥100MW Pre 70% Power Park
Module Tests
OC5.A.3.3.1
Before 70% but with at least 50% of the Power Park Module commissioned the following
Limited Frequency Sensitive tests as detailed in OC5.A.3.6.2 must be completed.
(a) BC3
(b) BC4
OC5.A.3.4
Reactive Capability Test
OC5.A.3.4.1
This section details the procedure for demonstrating the reactive capability of an Onshore
Power Park Module or an Offshore Power Park Module or OTSUA which provides all or a
portion of the Reactive Power capability as described in CC.6.3.2(e)(iii) (for the avoidance
of doubt, an Offshore Power Park Module which does not provide part of the Offshore
Transmission Licensee Reactive Power capability as described in CC6.3.2(e)(i) and
CC6.3.2(e)(ii) should complete the reactive power transfer / voltage control tests as per
section OC5.A.3.8). These tests should be scheduled at a time where there are at least 95%
of the Power Park Units within the Power Park Module in service. There should be
sufficient MW resource forecasted in order to generate at least 85% of Registered Capacity
of the Power Park Module.
OC5.A.3.4.2
The tests shall be performed by modifying the voltage set-point of the voltage control
scheme of the Power Park Module or OTSUA by the amount necessary to demonstrate the
required reactive range. This is to be conducted for the operating points and durations
specified in OC5.A.3.4.5.
OC5.A.3.4.3
Embedded Generator should liaise with the relevant Network Operator to ensure the
following tests will not have an adverse impact upon the Network Operator’s System as
per OC.7.5. In situations where the tests have an adverse impact upon the Network
Operator’s System NGET will only require demonstration within the acceptable limits of the
Network Operator. For the avoidance of doubt, these tests do not negate the requirement to
produce a complete Power Park Module performance chart as specified in OC2.4.2.1
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OC5.A.3.4.4
In the case where the Reactive Power metering point is not at the same location as the
Reactive Power capability requirement, then an equivalent Reactive Power capability for
the metering point shall be agreed between the Generator and NGET.
OC5.A.3.4.5
The following tests shall be completed:
(i)
Operation in excess of 50% Rated MW and maximum continuous lagging Reactive
Power for 60 minutes.
(ii)
Operation in excess of 50% Rated MW and maximum continuous leading Reactive
Power for 60 minutes.
(iii) Operation at 50% Rated MW and maximum continuous leading Reactive Power for 5
minutes.
(iv) Operation at 20% Rated MW and maximum continuous leading Reactive Power for 5
minutes.
(v) Operation at 20% Rated MW and maximum continuous lagging Reactive Power for 5
minutes.
(vi) Operation at less than 20% Rated MW and unity Power Factor for 5 minutes. This test
only applies to systems which do not offer voltage control below 20% of Rated MW.
(vii) Operation at 0% Rated MW and maximum continuous leading Reactive Power for 5
minutes. This test only applies to systems which offer voltage control below 20% and
hence establishes actual capability rather than required capability.
(viii) Operation at 0% Rated MW and maximum continuous lagging Reactive Power for 5
minutes. This test only applies to systems which offer voltage control below 20% and
hence establishes actual capability rather than required capability.
OC5.A.3.4.6
Within this OC lagging Reactive Power is the export of Reactive Power from the Power
Park Module to the Total System and leading Reactive Power is the import of Reactive
Power from the Total System to the Power Park Module or OTSUA.
OC5.A.3.4.7
Where the Generator provides a report from a Power Park Unit manufacturer validating the
full Reactive Power capability envelope of the Power Park Unit by test results acceptable
to NGET, NGET may agree a reduction from the set of tests detailed in OC5.A.3.4.5. The
validation testing detailed in the report must fully demonstrate the Reactive Power capability
across both the Active Power range and the range of unit terminal voltages.
OC5.A.3.5
Voltage Control Tests
OC5.A.3.5.1
This section details the procedure for conducting voltage control tests on Onshore Power
Park Modules or OTSUA or an Offshore Power Park Module which provides all or a
portion of the voltage control capability as described in CC.6.3.8(b)(ii) (for the avoidance of
doubt, Offshore Power Park Modules which do not provide part of the Offshore
Transmission Licensee voltage control capability as described in CC6.3.8(b)(i) should
complete the reactive power transfer / voltage control tests as per section OC5.A.3.8). These
tests should be scheduled at a time when there are at least 95% of the Power Park Units
within the Power Park Module in service. There should be sufficient MW resource
forecasted in order to generate at least 65% of Registered Capacity of the Onshore Power
Park Module. An Embedded Generator should also liaise with the relevant Network
Operator to ensure all requirements covered in this section will not have a detrimental effect
on the Network Operator’s System.
OC5.A.3.5.2
The voltage control system shall be perturbed with a series of step injections to the Power
Park Module voltage reference, and where possible, multiple up-stream transformer taps. In
the case of an Offshore Power Park Module providing part of the Offshore Transmission
Licensee voltage control capability this may require a series of step injections to the voltage
reference of the Offshore Transmission Licensee control system.
OC5.A.3.5.3
For steps initiated using network tap changers the Generator will need to coordinate with
NGET or the relevant Network Operator as appropriate. The time between transformer
taps shall be at least 10 seconds as per OC5.A.3.5 Figure 1.
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OC5.A.3.5.4
For step injection into the Power Park Module or OTSUA voltage reference, steps of ±1%
and ±2% shall be applied to the voltage control system reference summing junction. The
injection shall be maintained for 10 seconds as per OC5.A.3.5 Figure 2.
OC5.A.3.5.5
Where the voltage control system comprises of discretely switched plant and apparatus
additional tests will be required to demonstrate that its performance is in accordance with
Grid Code and Bilateral Agreement requirements.
OC5.A.3.5.6
Tests to be completed:
(i)
Voltage
Time
1 tap
10s
minimum
OC5.A.3.5 Figure 1 – Transformer tap sequence for voltage control tests
(ii)
Applied
Voltage
Step
2%
1%
Time
10s
OC5.A.3.5 Figure 2 – Step injection sequence for voltage control tests
OC.A.3.5.7
In the case of OTSUA where the Bilateral Agreement specifies additional damping
facilities, additional testing to demonstrate these damping facilities may be required.
OC5.A.3.6
Frequency Response Tests
OC5.A.3.6.1
This section describes the procedure for performing frequency response testing on an
Power Park Module. These tests should be scheduled at a time where there are at least
95% of the Power Park Units within the Power Park Module in service. There should be
sufficient MW resource forecasted in order to generate at least 65% of Registered Capacity
of the Power Park Module.
OC5.A.3.6.2
The frequency controller shall be in Frequency Sensitive Mode or Limited Frequency
Sensitive Mode as appropriate for each test. Simulated frequency deviation signals shall be
injected into the frequency controller reference/feedback summing junction. If the injected
frequency signal replaces rather than sums with the real system frequency signal then the
additional tests outlined in OC5.A.3.6.6 shall be performed with the Power Park Module or
Power Park Unit in normal Frequency Sensitive Mode monitoring actual system
frequency, over a period of at least 10 minutes. The aim of this additional test is to verify that
the control system correctly measures the real system frequency for normal variations over a
period of time.
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OC5.A.3.6.3
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In addition to the frequency response requirements it is necessary to demonstrate the Power
Park Module ability to deliver a requested steady state power output which is not impacted
by power source variation as per CC.6.3.9. This test shall be conducted in Limited
Frequency Sensitive Mode at a part-loaded output for a period of 10 minutes as per
OC5.A.3.6.6.
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Preliminary Frequency Response Testing
OC5.A.3.6.4
Prior to conducting the full set of tests as per OC5.A.3.6.6, Generators are required to
conduct the preliminary set of tests below to confirm the frequency injection method is
correct and the plant control performance is within expectation. The test numbers refer to
Figure 1 below. The test should be conducted when sufficient MW resource is forecasted in
order to generate at least 65% of Registered Capacity of the Power Park Module. The
following frequency injections shall be applied when operating at module load point 4.
Test No
(Figure 1)
8
14
13
OC5.A.3.6.5
Frequency Injection
Notes

Inject - 0.5Hz frequency fall over 10 sec

Hold until conditions stabilise

Remove the injected signal

Inject +0.5Hz frequency rise over 10 sec

Hold until conditions stabilise

Remove the injected signal

Inject -0.5Hz frequency fall over 10 sec

Hold for a further 20 sec

At 30 sec from the start of the test, Inject
a +0.3Hz frequency rise over 30 sec.

Hold until conditions stabilise

Remove the injected signal
The recorded results (e.g. Finj, MW and control signals) should be sampled at a minimum
rate of 1 Hz to allow NGET to assess the plant performance from the initial transients
(seconds) to the final steady state conditions (5-15 minutes depending on the plant design).
This is not witnessed by NGET. The Generator shall supply the recordings including data to
NGET in an electronic spreadsheet format. Results shall be legible, identifiable by labelling,
and shall have appropriate scaling.
Full Frequency Response Testing Schedule Witnessed by NGET
OC5.A.3.6.6
The tests are to be conducted at a number of different Module Load Points (MLP). In the
case of a Power Park Module the module load points are conducted as shown below unless
agreed otherwise by NGET.
Module Load Point 6
(Maximum Export Limit)
100% MEL
Module Load Point 5
90% MEL
Module Load Point 4
(Mid point of Operating Range)
80% MEL
Module Load Point 3
DMOL + 20%
Module Load Point 2
DMOL + 10%
Module Load Point 1
(Design Minimum Operating Level)
OC5.A.3.6.7
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DMOL
The tests are divided into the following two types;
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OC5.A.3.6.8
(i)
Frequency response volume tests as per OC5.A.3.6. Figure 1. These tests consist of
frequency profile and ramp tests.
(ii)
System islanding and step response tests as shown by OC5.A.3.6 Figure 2
There should be sufficient time allowed between tests for control systems to reach steady
state (depending on available power resource). Where the diagram states ‘HOLD’ the
current injection should be maintained until the Active Power (MW) output of the Power
Park Module has stabilised. All frequency response tests should be removed over the same
timescale for which they were applied. NGET may require repeat tests should the response
volume be affected by the available power, or if tests give unexpected results.
0.6
HOLD
0.4
Frequency (Hz)
HOLD
0.2
HOLD
0 10s 30s
60s
10s
10s
10s
10s
10s
0 10s 30s
60s
10s
HOLD
HOLD
HOLD
-0.2
-0.4
HOLD
-0.6
HOLD
0
-0.8
Typical
Response (MW)
+
0
_
Load
Point
LF Event
Profile 1
LF Ramp
-0.1Hz
HF Ramp
+0.1Hz
LF Ramp
-0.2Hz
HF Ramp
+0.2Hz
LF Ramp
-0.5Hz
HF Ramp
+0.5Hz
LF Event
Profile 2
MLP6
*
*
1
2
3
*
4
*
MLP5
5
*
*
6
*
*
7
*
MLP4
8
9
10
11
12
13
14
*
MLP3
15
*
*
*
*
*
16
17
MLP2
18
*
*
19
20
21
*
22
MLP1
23
*
*
24
25
*
*
26
OC5.A.3.6. Figure 1 – Frequency response volume tests
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HOLD
0.8
*
HOLD
0.6
HOLD
HOLD
0.2
0
0 1s
HOLD
0 1s (G) 31s
0 2s (A,J) 32s
HOLD
Frequency (Hz)
0.4
-0.2
0 30s
HOLD
-0.4
HOLD
-0.6
HOLD
-0.5Hz (K)
-2Hz (A,J)
-0.8
Typical
Response (MW)
+
0
_
Load Point +2.0*
+0.02
-0.2
+0.2
-0.5
+0.5
+0.6
MLP6
BC1
BC2
MLP6 LFSM
BC3
BC4
-0.5 -2.0
MLP5
+ 0**
L
A
MLP4
D/E
F
G
H
I
J
M
*
MLP4 LFSM
N
MLP3
MLP2
MLP1
K
OC5.A.3.6. Figure 2 – System islanding and step response tests
* This will generally be +2.0Hz unless an injection of this size causes a reduction in plant
output that takes the operating point below Designed Minimum Operating Level in which
case an appropriate injection should be calculated in accordance with the following:
For example 0.9Hz is needed to take an initial output 65% to a final output of 20%. If the
initial output was not 65% and the Designed Minimum Operating Level is not 20% then the
injected step should be adjusted accordingly as shown in the example given below
Initial Output
65%
Designed Minimum Operating Level
20%
Frequency Controller Droop
4%
Frequency to be injected =
(0.65 - 0.20) x 0.04 x 50 = 0.9Hz
** Tests L and M in Figure 2 shall be conducted if in this range of tests the system frequency
feedback signal is replaced by the injection signal rather than the injection signal being
added to the system frequency signal. The tests will consist of monitoring the Power Park
Module in Frequency Sensitive Mode during normal system frequency variations without
applying any injection. Test N in Figure 2 shall be conducted in all cases. All three tests
should be conducted for a period of at least 10 minutes.
OC5.A.3.7
Fault Ride Through Testing
OC5.A.3.7.1
This section describes the procedure for conducting fault ride through tests on a single
Power Park Unit.
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OC5.A.3.7.2
The test circuit will utilise the full Power Park Unit with no exclusions (e.g. in the case of a
wind turbine it would include the full wind turbine structure) and shall be conducted with
sufficient resource available to produce at least 95% of the Registered Capacity of the
Power Park Unit. The test will comprise of a number of controlled short circuits applied to a
test network to which the Power Park Unit is connected, typically comprising of the Power
Park Unit transformer and a test impedance to shield the connected network from voltage
dips at the Power Park Unit terminals.
OC5.A.3.7.3
In each case the tests should demonstrate the minimum voltage at the Power Park Unit
terminals or High Voltage side of the Power Park Unit transformer which the Power Park
Unit can withstand for the length of time specified in OC5.A.3.7.5. Any test results provided
to NGET should contain sufficient data pre and post fault in order to determine steady state
values of all signals, and the power recovery timescales.
OC5.A.3.7.4
In addition to the signals outlined in OC5.A.1.2. the following signals from either the Power
Park Unit terminals or High Voltage side of the Power Park Unit transformer should be
provided for this test only:
(i)
Phase voltages
(ii)
Positive phase sequence and negative phase sequence voltages
(iii) Phase currents
(iv) Positive phase sequence and negative phase sequence currents
(v) Estimate of Power Park Unit negative phase sequence impedance
(vi) MW – Active Power at the generating unit.
(vii) MVAr – Reactive Power at the generating unit.
(viii) Mechanical Rotor Speed
(ix) Real / reactive, current / power reference as appropriate
(x) Fault ride through protection operation (e.g. a crowbar in the case of a doubly fed
induction generator)
(xi) Any other signals relevant to the control action of the fault ride through control deemed
applicable for model validation.
At a suitable frequency rate for fault ride through tests as agreed with NGET.
OC5.A.3.7.5
The tests should be conducted for the times and fault types indicated in OC5.A.3.7 Table 1.
3 Phase
Phase to Phase
2 Phase to
Earth
1 Phase to
Earth
Grid Code Ref
0.14s
0.14s
0.14s
0.14s
CC.6.3.15a
0.384s
CC.6.3.15b
0.710s
2.5s
180.0s
OC5.A.3.7 Table 1 – Types of fault for fault ride through testing
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OC5.A.3.8
Reactive Power Transfer / Voltage Control Tests for Offshore Power Park Modules
OC5.A.3.8.1
In the case of an Offshore Power Park Module which provides all or a portion of the
Reactive Power capability as described in CC.6.3.2(e)(iii) and / or voltage control
requirements as described in CC.6.3.8(b)(ii) to enable an Offshore Transmission Licensee
to meet the requirements of STC Section K, the testing, will comprise of the entire control
system responding to changes at the onshore Interface Point. Therefore the tests in this
section OC5.A.3.8 will not apply. The Generator shall cooperate with the relevant Offshore
Transmission Licensee to facilitate these tests as required by NGET. The testing may be
combined with testing of the corresponding Offshore Transmission Licensee requirements
under the STC. The results in relation to the Offshore Power Park Module will be assessed
against the requirements in the Bilateral Agreement.
OC5.A.3.8.2
In the case of an Offshore Power Park Module which does not provide part of the Offshore
Transmission Licensee Reactive Power capability the following procedure for conducting
reactive power transfer control tests on Offshore Power Park Modules and / or voltage
control system as per CC6.3.2(e)(i) and CC6.3.2(e)(ii) apply. These tests should be carried
out prior to 20% of the Power Park Units within the Offshore Power Park Module being
synchronised, and again when at least 95% of the Power Park Units within the Offshore
Power Park Module in service. There should be sufficient power resource forecast to
generate at least 85% of the Registered Capacity of the Offshore Power Park Module.
OC5.A.3.8.3
The Reactive Power control system shall be perturbed by a series of system voltage
changes and changes to the Active Power output of the Offshore Power Park Module.
OC5.A.3.8.4
System voltage changes should be created by a series of multiple upstream transformer
taps. The Generator should coordinate with NGET or the relevant Network Operator in
order to conduct the required tests. The time between transformer taps should be at least 10
seconds as per OC5.A.3.8 Figure 1.
OC5.A.3.8.5
The active power output of the Offshore Power Park Module should be varied by applying
a sufficiently large step to the frequency controller reference/feedback summing junction to
cause a 10% change in output of the Registered Capacity of the Offshore Power Park
Module in a time not exceeding 10 seconds. This test does not need to be conducted
provided that the frequency response tests as outlined in OC5.A.3.6 are completed.
OC5.A.3.8.6
The following diagrams illustrate the tests to be completed:
Voltage
Time
1 tap
>10s
OC5.A.3.8 Figure 1 – Transformer tap sequence for reactive transfer tests
<=10s
Active
Power
Change
Time
10% of
Registered Capacity
OC5.A.3.8 Figure 2 – Active Power ramp for reactive transfer tests
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APPENDIX 4 - COMPLIANCE TESTING FOR DC CONVERTERS AT A DC
CONVERTER STATION
OC5.A.4.1
Scope
OC5.A.4.1.1
This Appendix outlines the general testing requirements for DC Converter Station owners
to demonstrate compliance with the relevant aspects of the Grid Code, Ancillary Services
Agreement and Bilateral Agreement. The tests specified in this Appendix will normally be
sufficient to demonstrate compliance however NGET may:
(i)
agree an alternative set of tests provided NGET deem the alternative set of tests
sufficient to demonstrate compliance with the Grid Code, Ancillary Services
Agreement and Bilateral Agreement; and/or
(ii)
require additional or alternative tests if information supplied to NGET during the
compliance process suggests that the tests in this Appendix will not fully demonstrate
compliance with the relevant section of the Grid Code, Ancillary Services Agreement
or Bilateral Agreement; and/or
(iii) require additional tests if control functions to improve damping of power system
oscillations and/or subsynchronous resonance torsional oscillations required by the
Bilateral Agreement or included in the control scheme and active; and/or
(iv) agree a reduced set of tests for subsequent DC Converters following successful
completion of the first DC Converter tests in the case of a Power Station comprised of
two or more DC Converters which NGET reasonably considers to be identical.
If:
(a) the tests performed pursuant to OC5.A.4.1.1(iv) in respect of subsequent DC
Converters do not replicate the full tests for the first DC Converter, or
(b) any of the tests performed pursuant to OC5.A.4.1.1(iv) do not fully demonstrate
compliance with the relevant aspects of the Grid Code, Ancillary Services Agreement
and / or Bilateral Agreement,
then notwithstanding the provisions above, the full testing requirements set out in this
Appendix will be applied.
OC5.A.4.1.2
The DC Converter Station owner is responsible for carrying out the tests set out in and in
accordance with this Appendix and the DC Converter Station owner retains the
responsibility for the safety of personnel and plant during the test. The DC Converter
Station owner is responsible for ensuring that suitable arrangements are in place with the
Externally Interconnected System Operator to facilitate testing. NGET will witness all of
the tests outlined or agreed in relation to this Appendix unless NGET decides and notifies
the DC Converter Station owner otherwise. Reactive Capability tests if required, may be
witnessed by NGET remotely from the NGET control centre. For all on site NGET witnessed
tests the DC Converter Station owner must ensure suitable representatives from the DC
Converter Station owner and / or DC Converter manufacturer (if appropriate) are available
on site for the entire testing period. In all cases and in addition to any recording of signals
conducted by NGET the DC Converter Station owner shall record all relevant test signals
as outlined in OC5.A.1.
OC5.A.4.1.3
In addition to the dynamic signals supplied in OC5.A.1 the DC Converter Station owner
shall inform NGET of the following information prior to the commencement of the tests and
any changes to the following, if any values change during the tests:
(i)
All relevant transformer tap numbers.
OC5.A.4.1.4
The DC Converter Station owner shall submit a detailed schedule of tests to NGET in
accordance with CP.6.3.1, and this Appendix.
OC5.A.4.1.5
Prior to the testing of a DC Converter the DC Converter Station owner shall complete the
Integral Equipment Tests procedure in accordance with OC.7.5
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OC5.A.4.1.6
Full DC Converter testing as required by CP.7.2 is to be completed as defined in OC5.A.4.2
through to OC5.A.4.5
OC5.A.4.2
Reactive Capability Test
OC5.A.4.2.1
This section details the procedure for demonstrating the reactive capability of an Onshore
DC Converter. These tests should be scheduled at a time where there are sufficient MW
resource forecasted in order to import and export full Registered Capacity of the DC
Converter.
OC5.A.4.2.2
The tests shall be performed by modifying the voltage set-point of the voltage control
scheme of the DC Converter by the amount necessary to demonstrate the required reactive
range. This is to be conducted for the operating points and durations specified in
OC5.A.4.2.5.
OC5.A.4.2.3
Embedded DC Converter Station owner should liaise with the relevant Network Operator
to ensure the following tests will not have an adverse impact upon the Network Operator’s
System as per OC.7.5. In situations where the tests have an adverse impact upon the
Network Operator’s System NGET will only require demonstration within the acceptable
limits of the Network Operator. For the avoidance of doubt, these tests do not negate the
requirement to produce a complete DC Converter performance chart as specified in
OC2.4.2.1.
OC5.A.4.2.4
In the case where the Reactive Power metering point is not at the same location as the
Reactive Power capability requirement, then an equivalent Reactive Power capability for
the metering point shall be agreed between the DC Converter Station owner and NGET.
OC5.A.4.2.5
The following tests shall be completed for both importing and exporting of Active Power for a
DC Converter (excluding current source technology):
(i)
Operation at Rated MW and maximum continuous lagging Reactive Power for 60
minutes.
(ii)
Operation at Rated MW and maximum continuous leading Reactive Power for 60
minutes.
(iii) Operation at 50% Rated MW and maximum continuous leading Reactive Power for 5
minutes.
(iv) Operation at 20% Rated MW and maximum continuous leading Reactive Power for 5
minutes.
(v) Operation at 20% Rated MW and maximum continuous lagging Reactive Power for 5
minutes.
(vi) Operation at less than 20% Rated MW and unity Power Factor for 5 minutes. This test
only applies to systems which do not offer voltage control below 20% of Rated MW.
(vii) Operation at 0% Rated MW and maximum continuous leading Reactive Power for 5
minutes. This test only applies to systems which offer voltage control below 20% and
hence establishes actual capability rather than required capability.
(viii) Operation at 0% Rated MW and maximum continuous lagging Reactive Power for 5
minutes. This test only applies to systems which offer voltage control below 20% and
hence establishes actual capability rather than required capability.
OC5.A.4.2.6
Issue 5 Revision 15
For the avoidance of doubt, lagging Reactive Power is the export of Reactive Power from
the DC Converter to the Total System and leading Reactive Power is the import of
Reactive Power from the Total System to the DC Converter.
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OC5.A.4.3
Reactive Control Testing For DC Converters (Current Source Technology)
OC5.A.4.3.1
The Reactive control testing for DC Converters employing current source technology shall
be for both importing and exporting of Active Power and shall demonstrate that the reactive
power transfer limits specified in the Bilateral Agreement are not exceeded. The Reactive
Power control system shall be perturbed by a series of system voltage changes to the
Active Power output of the DC Converter and changes of system voltage where possible.
The DC Converter Station owner is responsible for ensuring that suitable arrangements are
in place with the Externally Interconnected System Operator to facilitate the active power
changes required by these tests
OC5.A.4.3.2
The active power output of the DC Converter should be varied by applying a sufficiently
large step to the frequency controller reference/feedback summing junction to cause at least
a 10% change in output of the Registered Capacity of the DC Converter in a time not
exceeding 10 seconds. This test does not need to be conducted provided that the frequency
response tests as outlined in OC5.A.4.3 are completed.
OC5.A.4.3.3
Where possible system voltage changes should be created by a series of multiple upstream
transformer taps. The DC Converter station owner should coordinate with NGET or the
relevant Network Operator in order to conduct the required tests. The time between
transformer taps should be at least 10 seconds as per OC5.A.4.3 Figure 1.
OC5.A.4.3.4
The following diagrams illustrate the tests to be completed:
Voltage
Time
1 tap
>10s
OC5.A.4.3 Figure 1 – Transformer tap sequence for reactive transfer tests
<=10s
Active
Power
Change
Time
10% of
Registered Capacity
OC5.A.4.3 Figure 2 – Active Power ramp for reactive transfer tests
OC5.A.4.4
Voltage Control Tests
OC5.A.4.4.1
This section details the procedure for conducting voltage control tests on DC Converters
(excluding current source technology). These tests should be scheduled at a time where
there are sufficient MW resource in order to import and export full Registered Capacity of
the DC Converter. An Embedded DC Converter Station owner should also liaise with the
relevant Network Operator to ensure all requirements covered in this section will not have a
detrimental effect on the Network Operator’s System.
OC5.A.4.4.2
The voltage control system shall be perturbed with a series of step injections to the DC
Converter voltage reference, and where possible, multiple up-stream transformer taps.
OC5.A.4.4.3
For steps initiated using network tap changers the DC Converter Station owner will need to
coordinate with NGET or the relevant Network Operator as appropriate. The time between
transformer taps shall be at least 10 seconds as per OC5.A.4.4 Figure 1.
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OC5.A.4.4.4
For step injection into the DC Converter voltage reference, steps of ±1% and ±2% shall be
applied to the voltage control system reference summing junction. The injection shall be
maintained for 10 seconds as per OC5.A.4.4 Figure 2.
OC5.A.4.4.5
Where the voltage control system comprises of discretely switched plant and apparatus
additional tests will be required to demonstrate that its performance is in accordance with
Grid Code and Bilateral Agreement requirements.
OC5.A.4.4.6
Tests to be completed:
(i)
Voltage
Time
1 tap
10s
minimum
OC5.A.4.4 Figure 1 – Transformer tap sequence for voltage control tests
(ii)
Applied
Voltage
Step
2%
1%
Time
10s
OC5.A.4.4 Figure 2 – Step injection sequence for voltage control tests
OC5.A.4.5
Frequency Response Tests
OC5.A.4.5.1
This section describes the procedure for performing frequency response testing on a DC
Converter. These tests should be scheduled at a time where there are sufficient MW
resource in order to import and export full Registered Capacity of the DC Converter. The
DC Converter Station owner is responsible for ensuring that suitable arrangements are in
place with the Externally Interconnected System Operator to facilitate the active power
changes required by these tests
OC5.A.4.5.2
The frequency controller shall be in Frequency Sensitive Mode or Limited Frequency
Sensitive Mode as appropriate for each test. Simulated frequency deviation signals shall be
injected into the frequency controller reference/feedback summing junction. If the injected
frequency signal replaces rather than sums with the real system frequency signal then the
additional tests outlined in OC5.A.4.5.6 shall be performed with the DC Converter in normal
Frequency Sensitive Mode monitoring actual system frequency, over a period of at least 10
minutes. The aim of this additional test is to verify that the control system correctly measures
the real system frequency for normal variations over a period of time.
OC5.A.4.5.3
In addition to the frequency response requirements it is necessary to demonstrate the DC
Converter ability to deliver a requested steady state power output which is not impacted by
power source variation as per CC.6.3.9. This test shall be conducted in Limited Frequency
Sensitive Mode at a part-loaded output for a period of 10 minutes as per OC5.A.4.5.6.
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Preliminary Frequency Response Testing
OC5.A.4.5.4
Prior to conducting the full set of tests as per OC5.A.4.5.6, DC Converter Station owners
are required to conduct a preliminary set of tests below to confirm the frequency injection
method is correct and the plant control performance is within expectation. The test numbers
refer to Figure 1 below. These tests should be scheduled at a time where there are sufficient
MW resource in order to export full Registered Capacity from the DC Converter. The
following frequency injections shall be applied when operating at module load point 4.
Test No
(Figure 1)
8
14
13
OC5.A.4.5.5
Frequency Injection
Notes

Inject - 0.5Hz frequency fall over 10 sec

Hold until conditions stabilise

Remove the injected signal

Inject +0.5Hz frequency rise over 10 sec

Hold until conditions stabilise

Remove the injected signal

Inject -0.5Hz frequency fall over 10 sec

Hold for a further 20 sec

At 30 sec from the start of the test, Inject
a +0.3Hz frequency rise over 30 sec.

Hold until conditions stabilise

Remove the injected signal
The recorded results (e.g. Finj, MW and control signals) should be sampled at a minimum
rate of 1 Hz to allow NGET to assess the plant performance from the initial transients
(seconds) to the final steady state conditions (5-15 minutes depending on the plant design).
This is not witnessed by NGET. The DC Converter Station owner shall supply the
recordings including data to NGET in an electronic spreadsheet format. Results shall be
legible, identifiable by labelling, and shall have appropriate scaling.
Full Frequency Response Testing Schedule Witnessed by NGET
OC5.A.4.5.6
The tests are to be conducted at a number of different Module Load Points (MLP). In the
case of a DC Converter the module load points are conducted as shown below unless
agreed otherwise by NGET.
Module Load Point 6
(Maximum Export Limit)
100% MEL
Module Load Point 5
90% MEL
Module Load Point 4
(Mid point of Operating Range)
80% MEL
Module Load Point 3
DMOL + 20%
Module Load Point 2
DMOL + 10%
Module Load Point 1
(Design Minimum Operating Level)
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OC5.A.4.5.7
The tests are divided into the following two types;
OC5.A.4.5.8
(i)
Frequency response volume tests as per OC5.A.4.5. Figure 1. These tests consist of
frequency profile and ramp tests.
(ii)
System islanding and step response tests as shown by OC5.A.4.5 Figure 2
There should be sufficient time allowed between tests for control systems to reach steady
state (depending on available power resource). Where the diagram states ‘HOLD’ the
current injection should be maintained until the Active Power (MW) output of the DC
Converter has stabilised. All frequency response tests should be removed over the same
timescale for which they were applied. NGET may require repeat tests should the response
volume be affected by the available power, or if tests give unexpected results.
0.6
HOLD
0.4
Frequency (Hz)
HOLD
0.2
HOLD
0 10s 30s
60s
10s
10s
10s
10s
10s
0 10s 30s
60s
10s
HOLD
HOLD
HOLD
-0.2
-0.4
HOLD
-0.6
HOLD
0
-0.8
Typical
Response (MW)
+
0
_
Load
Point
LF Event
Profile 1
LF Ramp
-0.1Hz
HF Ramp
+0.1Hz
LF Ramp
-0.2Hz
HF Ramp
+0.2Hz
LF Ramp
-0.5Hz
HF Ramp
+0.5Hz
LF Event
Profile 2
MLP6
*
*
1
2
3
*
4
*
MLP5
5
*
*
6
*
*
7
*
MLP4
8
9
10
11
12
13
14
*
MLP3
15
*
*
*
*
*
16
17
MLP2
18
*
*
19
20
21
*
22
MLP1
23
*
*
24
25
*
*
26
OC5.A.4.5. Figure 1 – Frequency response volume tests
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HOLD
0.8
*
HOLD
0.6
HOLD
HOLD
0.2
0
0 1s
HOLD
0 1s (G) 31s
0 2s (A,J) 32s
HOLD
Frequency (Hz)
0.4
-0.2
0 30s
HOLD
-0.4
HOLD
-0.6
HOLD
-0.5Hz (K)
-2Hz (A,J)
-0.8
Typical
Response (MW)
+
0
_
Load Point +2.0*
+0.02
-0.2
+0.2
-0.5
+0.5
+0.6
MLP6
BC1
BC2
MLP6 LFSM
BC3
BC4
MLP5
-0.5 -2.0
+ 0**
L
A
MLP4
D/E
F
G
H
I
J
M
*
MLP4 LFSM
N
MLP3
MLP2
MLP1
K
OC5.A.4.5. Figure 2 – System islanding and step response tests
* This will generally be +2.0Hz unless an injection of this size causes a reduction in plant
output that takes the operating point below Designed Minimum Operating Level in which
case an appropriate injection should be calculated in accordance with the following:
For example 0.9Hz is needed to take an initial output 65% to a final output of 20%. If the
initial output was not 65% and the Designed Minimum Operating Level is not 20% then the
injected step should be adjusted accordingly as shown in the example given below
Initial Output
65%
Designed Minimum Operating Level
20%
Frequency Controller Droop
4%
Frequency to be injected =
(0.65 - 0.20) x 0.04 x 50 = 0.9Hz
** Tests L and M in Figure 2 shall be conducted if in this range of tests the system frequency
feedback signal is replaced by the injection signal rather than the injection signal being
added to the system frequency signal. The tests will consist of monitoring the DC Converter
in Frequency Sensitive Mode during normal system frequency variations without applying
any injection. Test N in Figure 2 shall be conducted in all cases. All three tests should be
conducted for a period of at least 10 minutes.
< END OF OPERATING CODE NO. 5 >
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OPERATING CODE NO. 6
(OC6)
DEMAND CONTROL
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
OC6.1 INTRODUCTION................................................................................................................................... 2
OC6.2 OBJECTIVE .......................................................................................................................................... 3
OC6.3 SCOPE .................................................................................................................................................. 3
OC6.4 PROCEDURE FOR THE NOTIFICATION OF DEMAND CONTROL INITIATED BY
NETWORK OPERATORS ................................................................................................................................. 4
OC6.5 PROCEDURE FOR THE IMPLEMENTATION OF DEMAND CONTROL ON THE
INSTRUCTIONS OF NGET................................................................................................................................ 5
OC6.6 AUTOMATIC LOW FREQUENCY DEMAND DISCONNECTION ........................................................ 8
OC6.7 EMERGENCY MANUAL DISCONNECTION ........................................................................................ 9
OC6.8 OPERATION OF THE BALANCING MECHANISM DURING DEMAND CONTROL ......................... 10
APPENDIX 1 - EMERGENCY MANUAL DEMAND REDUCTION/DISCONNECTION SUMMARY
SHEET .............................................................................................................................................................. 11
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OC6.1
INTRODUCTION
OC6.1.1
Operating Code No.6 ("OC6") is concerned with the provisions to be made by Network
Operators, and in relation to Non-Embedded Customers by NGET, to permit the reduction of
Demand in the event of insufficient Active Power generation being available to meet Demand,
or in the event of breakdown or operating problems (such as in respect of System Frequency,
System voltage levels or System thermal overloads) on any part of the National Electricity
Transmission System.
OC6.1.2
OC6 deals with the following:
(a) Customer voltage reduction initiated by Network Operators (other than following the
instruction of NGET);
(b) Customer Demand reduction by Disconnection initiated by Network Operators (other
than following the instruction of NGET);
(c) Demand reduction instructed by NGET;
(d) automatic low frequency Demand Disconnection; and
(e) emergency manual Demand Disconnection.
The term "Demand Control" is used to describe any or all of these methods of achieving a
Demand reduction.
OC6.1.3
The procedure set out in OC6 includes a system of warnings to give advance notice of Demand
Control that may be required by NGET under this OC6.
OC6.1.4
Data relating to Demand Control should include details relating to MW
OC6.1.5
The Electricity Supply Emergency Code as reviewed and published from time to time by the
appropriate government department for energy emergencies provides that in certain
circumstances consumers are given a certain degree of "protection" when rota disconnections
are implemented pursuant to a direction under the Energy Act 1976. No such protection can be
given in relation to Demand Control under the Grid Code.
To invoke the Electricity Supply Emergency Code the Secretary of State will issue direction(s) to
all Network Operators affected, exercising emergency powers under the Electricity Act 1989 or
by virtue of an Order in Council under the Energy Act 1976. Following the issuance of such
direction, NGET will act to coordinate the implementation of an agreed schedule of rota
disconnections across all affected Network Operators’ licence area(s) and to disseminate any
information as necessary throughout the period of the emergency in accordance with the
instructions NGET receives from the Secretary of State or those authorised on his behalf for this
purpose.
OC6.1.6
Connections between Large Power Stations and the National Electricity Transmission
System and between such Power Stations and a User System will not, as far as possible, be
disconnected by NGET pursuant to the provisions of OC6 insofar as that would interrupt supplies
(a) for the purposes of operation of the Power Station (including Start-Up and shutting down);
(b) for the purposes of keeping the Power Station in a state such that it could be Started-up
when it is off-Load for ordinary operational reasons; or
(c) for the purposes of compliance with the requirements of a Nuclear Site Licence.
Demand Control pursuant to this OC6 therefore applies subject to this exception.
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OC6.2
OBJECTIVE
OC6.2.1
The overall objective of OC6 is to require the provision of facilities to enable NGET to achieve
reduction in Demand that will either avoid or relieve operating problems on the National
Electricity Transmission System, in whole or in part, and thereby to enable NGET to instruct
Demand Control in a manner that does not unduly discriminate against, or unduly prefer, any
one or any group of Suppliers or Network Operators or Non-Embedded Customers. It is also
to ensure that NGET is notified of any Demand Control utilised by Users other than following an
instruction from NGET.
OC6.2.2
For certain Grid Supply Points in Scotland it is recognised that it may not be possible to meet
the requirements in OC6.4.5(b), OC6.5.3(b) (in respect of Demand Disconnection only),
OC6.5.6 (ii), OC6.6.2 (c) and OC6.7.2 (b). In these circumstances NGET and the relevant
Network Operator(s) will agree equivalent requirements covering a number of Grid Supply
Points. If NGET and the relevant Network Operator fail to agree equivalent requirements
covering a number of Grid Supply Points, then the relevant Network Operator will apply the
provisions of OC6.4.5(b), OC6.5.3(b) (in respect of Demand Disconnection only), OC6.5.6(ii),
OC6.6.2(c) and OC6.7.2(b) as evenly as reasonably practicable over the relevant Network
Operator’s entire System.
OC6.3
SCOPE
OC6.3.1
OC6 applies to NGET and to Users which in OC6 means:
(a) Generators; and
(b) Network Operators.
It also applies to NGET in relation to Non-Embedded Customers.
OC6.3.2
Explanation
OC6.3.2.1
(a) Although OC6 does not apply to Suppliers, the implementation of Demand Control may
affect their Customers.
(b) In all situations envisaged in OC6, Demand Control is exercisable:
(i)
by reference to a Network Operator's System; or
(ii)
by NGET in relation to Non-Embedded Customers.
(c) Demand Control in all situations relates to the physical organisation of the Total System,
and not to any contractual arrangements that may exist.
OC6.3.2.2
(a) Accordingly, Demand Control will be exercisable with reference to, for example, five per
cent (or such other figure as may be utilised under OC6.5) tranches of Demand by a
Network Operator.
(b) For a Supplier, whose Customers may be spread throughout a number of User Systems
(and the National Electricity Transmission System), to split its Customers into five per
cent (or such other figure as may be utilised under OC6.5) tranches of Demand would not
result in Demand Control being implemented effectively on the Total System.
(c) Where Demand Control is needed in a particular area, NGET would not know which
Supplier to contact and (even if it were to) the resulting Demand Control implemented,
because of the diversity of contracts, may well not produce the required result.
OC6.3.2.3
(a) Suppliers should note, however, that, although implementation of Demand Control in
respect of their Customers is not exercisable by them, their Customers may be affected by
Demand Control.
(b) This will be implemented by Network Operators where the Customers are within User
Systems directly connected to the National Electricity Transmission System and by
NGET where they are Non-Embedded Customers.
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(c) The contractual arrangements relating to Customers being supplied by Suppliers will,
accordingly, need to reflect this.
(d) The existence of a commercial arrangement for the provision of Customer Demand
Management or Commercial Ancillary Services does not relieve a Network Operator
from the Demand Control provisions of OC6.5, OC6.6 and OC6.7, which may be exercised
from time to time.
OC6.4
PROCEDURE FOR THE NOTIFICATION OF DEMAND CONTROL INITIATED BY NETWORK
OPERATORS (OTHER THAN FOLLOWING THE INSTRUCTION OF NGET)
OC6.4.1
Pursuant to the provisions of OC1, in respect of the time periods prior to 1100 hours each day,
each Network Operator will notify NGET of all Customer voltage reductions and/or restorations
and Demand Disconnection or reconnection, on a Grid Supply Point and half-hourly basis,
which will or may, either alone or when aggregated with any other Demand Control planned by
that Network Operator, result in a Demand change equal to or greater than the Demand
Control Notification Level averaged over any half hour on any Grid Supply Point, which is
planned to be instructed by the Network Operator other than following an instruction from
NGET relating to Demand reduction.
OC6.4.2
Under OC6, each Network Operator will notify NGET in writing by 1100 hours each day (or such
other time specified by NGET from time to time) for the next day (except that it will be for the
next 3 days on Fridays and 2 days on Saturdays and may be longer (as specified by NGET at
least one week in advance) to cover holiday periods) of Customer voltage reduction or Demand
Disconnection which will or may result in a Demand change equal to or greater than the
Demand Control Notification Level averaged over any half hour on any Grid Supply Point, (or
which when aggregated with any other Demand Control planned by that Network Operator is
equal to or greater than the Demand Control Notification Level), planned to take place during
the next Operational Day.
OC6.4.3
When the Customer voltage reduction or Demand Disconnection which may result in a
Demand change equal to or greater than the Demand Control Notification Level averaged
over any half hour on any Grid Supply Point (or which when aggregated with any other
Demand Control planned or implemented by that Network Operator is equal to or greater than
the Demand Control Notification Level) is planned after 1100 hours, each Network Operator
must notify NGET as soon as possible after the decision to implement has been made. If the
Customer voltage reduction or Demand Disconnection is implemented immediately after the
decision to implement is made, each Network Operator must notify NGET within five minutes of
implementation.
OC6.4.4
Where, after NGET has been notified, whether pursuant to OC1, OC6.4.2 or OC6.4.3, the
planned Customer voltage reduction or Demand Disconnection is changed, the Network
Operator will notify NGET as soon as possible of the new plans, or if the Customer voltage
reduction or Demand Disconnection implemented is different to that notified, the Network
Operator will notify NGET of what took place within five minutes of implementation.
OC6.4.5
Any notification under OC6.4.2, OC6.4.3 or OC6.4.4 will contain the following information on a
Grid Supply Point and half hourly basis:
(a) the proposed (in the case of prior notification) and actual (in the case of subsequent
notification) date, time and duration of implementation of the Customer voltage reduction or
Demand Disconnection; and
(b) the proposed reduction in Demand by use of the Customer voltage reduction or Demand
Disconnection.
OC6.4.6
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Pursuant to the provisions of OC1.5.6, each Network Operator will supply to NGET details of
the amount of Demand reduction actually achieved by use of the Customer voltage reduction or
Demand Disconnection.
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OC6.5
PROCEDURE FOR THE IMPLEMENTATION OF DEMAND CONTROL ON THE
INSTRUCTIONS OF NGET
OC6.5.1
A National Electricity Transmission System Warning - High Risk of Demand Reduction
will, where possible, be issued by NGET, as more particularly set out in OC6.5.4, OC7.4.8 and
BC1.5.4 when NGET anticipates that it will or may instruct a Network Operator to implement
Demand reduction. It will, as provided in OC6.5.10 and OC7.4.8.2, also be issued to NonEmbedded Customers.
OC6.5.2
Where NGET expects to instruct Demand reduction within the following 30 minutes, NGET will
where possible, issue a National Electricity Transmission System Warning - Demand
Control Imminent in accordance with OC7.4.8.2(c) and OC7.4.8.6.
OC6.5.3
(a) Whether a National Electricity Transmission System Warning - High Risk of Demand
Reduction or National Electricity Transmission System Warning - Demand Control
Imminent has been issued or not:
(i)
provided the instruction relates to not more than 20 per cent of its total Demand
(measured at the time the Demand reduction is required); and
(ii)
if the instruction relates to less than 20 per cent of its total Demand, is in

two voltage reduction stages of between 2 and 4 percent, each of which can be
expected to deliver around 1.5 percent Demand reduction; and

up to three Demand Disconnection stages, each of which can reasonably be
expected to deliver between four and six percent Demand reduction,
each Network Operator will abide by the instructions of NGET, which should
specify whether a voltage reduction or Demand Disconnection stage is required;
or
(iii) if the instruction relates to less than 20 per cent of its total Demand, is in four
Demand Disconnection stages each of which can reasonably be expected to
deliver between four and six per cent Demand reduction,
each Network Operator will abide by the instructions of NGET with regard to Demand
reduction under OC6.5 without delay.
(b) The Demand reduction must be achieved within the Network Operator's System as far as
possible uniformly across all Grid Supply Points (unless otherwise specified in the
National Electricity Transmission System Warning - High Risk of Demand Reduction)
either by Customer voltage reduction or by Demand Disconnection.
(c) Demand Control initiated by voltage reduction shall be initiated as soon as possible but in
any event no longer than two minutes from the instruction being received from NGET, and
completed within 10 minutes of the instruction being received from NGET.
(d) Demand Control initiated by Demand Disconnection shall be initiated as soon as possible
but in any event no longer than two minutes from the instruction being received from NGET,
and completed within five minutes of the instruction being received from NGET.
(e) Each Network Operator must notify NGET in writing by calendar week 24 each year, for
the succeeding Financial Year onwards, whether Demand Control is to be implemented
either:
i)
by a combination of voltage reduction and Demand Disconnection; or
ii) Demand Disconnection alone;
together with the magnitude of the voltage reduction stages (where applicable) and for
Demand Disconnection stages, the demand reduction anticipated. Thereafter, any
changes must be notified in writing to NGET at least 10 Business Days prior to the change
coming into effect.
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OC6.5.4
(a) Where NGET wishes to instruct a Demand reduction of more than 20 per cent of a
Network Operator's Demand (measured at the time the Demand reduction is required), it
shall, if it is able, issue a National Electricity Transmission System Warning - High Risk
of Demand Reduction to the Network Operator by 1600 hours on the previous day. The
warning will state the percentage level of Demand reduction that NGET may want to
instruct (measured at the time the Demand reduction is required).
(b) The National Electricity Transmission System Warning - High Risk of Demand
Reduction will specify the percentage of Demand reduction that NGET may require in
integral multiples of the percentage levels notified by Users under OC6.5.3(c) up to (and
including) 20 per cent and of five per cent above 20 per cent and will not relate to more than
40 per cent of Demand (measured at the time the Demand reduction is required) of the
Demand on the User System of a Network Operator.
(c) If NGET has issued the National Electricity Transmission System Warning - High Risk
of Demand Reduction by 1600 hours on the previous day, on receipt of it the relevant
Network Operator shall make available the percentage reduction in Demand specified for
use within the period of the National Electricity Transmission System Warning.
(d) If NGET has not issued the National Electricity Transmission System Warning - High
Risk of Demand Reduction by 1600 hours the previous day, but after that time, the
Network Operator shall make available as much of the required Demand reduction as it is
able, for use within the period of the National Electricity Transmission System Warning.
OC6.5.5
(a) If NGET has given a National Electricity Transmission System Warning - High Risk of
Demand Reduction to a Network Operator, and has issued it by 1600 hours on the
previous day, it can instruct the Network Operator to reduce its Demand by the
percentage specified in the National Electricity Transmission System Warning.
(b) NGET accepts that if it has not issued the National Electricity Transmission System
Warning - High Risk of Demand Reduction by 1600 hours on the previous day or if it has
issued it by 1600 hours on the previous day, but it requires a further percentage of Demand
reduction (which may be in excess of 40 per cent of the total Demand on the User System
of the Network Operator (measured at the time the Demand reduction is required) from
that set out in the National Electricity Transmission System Warning, it can only receive
an amount that can be made available at that time by the Network Operator.
(c) Other than with regard to the proviso, the provisions of OC6.5.3 shall apply to those
instructions.
OC6.5.6
Once a Demand reduction has been applied by a Network Operator at the instruction of NGET,
the Network Operator may interchange the Customers to whom the Demand reduction has
been applied provided that,
(i)
the percentage of Demand reduction at all times within the Network Operator's System
does not change; and
(ii)
at all times it is achieved within the Network Operator's System as far as possible
uniformly across all Grid Supply Points (unless otherwise specified in the National
Electricity Transmission System Warning - High Risk of Demand Reduction if one has
been issued),
until NGET instructs that Network Operator in accordance with OC6.
OC6.5.7
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Each Network Operator will abide by the instructions of NGET with regard to the restoration of
Demand under OC6.5 without delay. It shall not restore Demand until it has received such
instruction. The restoration of Demand must be achieved as soon as possible and the process
of restoration must begin within 2 minutes of the instruction being given by NGET.
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OC6.5.8
In circumstances of protracted shortage of generation or where a statutory instruction has been
given (eg. a fuel security period) and when a reduction in Demand is envisaged by NGET to be
prolonged, NGET will notify the Network Operator of the expected duration.
OC6.5.9
The Network Operator will notify NGET in writing that it has complied with NGET's instruction
under OC6.5, within five minutes of so doing, together with an estimation of the Demand
reduction or restoration achieved, as the case may be.
OC6.5.10
NGET may itself implement Demand reduction and subsequent restoration on Non-Embedded
Customers as part of a Demand Control requirement and it will organise the National
Electricity Transmission System so that it will be able to reduce Demand by Disconnection
of, or Customer voltage reduction to, all or any Non-Embedded Customers. Equivalent
provisions to those in OC6.5.4 shall apply to issuing a National Electricity Transmission
System Warning - High Risk of Demand Reduction to Non-Embedded Customers, as
envisaged in OC7.4.8.
OC6.5.11
Pursuant to the provisions of OC1.5.6, the Network Operator will supply to NGET details of the
amount of Demand reduction or restoration actually achieved.
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OC6.6
AUTOMATIC LOW FREQUENCY DEMAND DISCONNECTION
OC6.6.1
Each Network Operator will make arrangements that will enable automatic low Frequency
Disconnection of at least:
(i)
60 per cent of its total Demand (based on Annual ACS Conditions) at the time of forecast
National Electricity Transmission System peak Demand where such Network
Operator’s System is connected to the National Electricity Transmission System in
NGET’s Transmission Area
(ii)
40 per cent of its total Demand (based on Annual ACS Conditions) at the time of forecast
National Electricity Transmission System peak where such Network Operator’s
System is connected to the National Electricity Transmission System in either SPT’s or
SHETL’s Transmission Area
in order to seek to limit the consequences of a major loss of generation or an Event on the Total
System which leaves part of the Total System with a generation deficit. Where a Network
Operator’s System is connected to the National Electricity Transmission System in more
than one Transmission Area, the figure above for the Transmission Area in which the majority
of the Network Operator’s Demand is connected shall apply.
OC6.6.2
(a) The Demand of each Network Operator which is subject to automatic low Frequency
Disconnection will be split into discrete MW blocks.
(b) The number, size (% Demand) and the associated low Frequency settings of these blocks,
will be as specified in Table CC.A.5.5.1a. NGET will keep the settings under review.
(c) The distribution of the blocks will be such as to give a reasonably uniform Disconnection
within the Network Operator's System, as the case may be, across all Grid Supply
Points.
(d) Each Network Operator will notify NGET in writing by calendar week 24 each year of the
details of the automatic low Frequency Disconnection on its User System. The
information provided should identify, for each Grid Supply Point at the date and time of the
annual peak of the National Electricity Transmission System Demand at Annual ACS
Conditions (as notified pursuant to OC1.4.2), the frequency settings at which Demand
Disconnection will be initiated and amount of Demand disconnected at each such setting.
OC6.6.3
Where conditions are such that, following automatic low Frequency Demand Disconnection,
and the subsequent Frequency recovery, it is not possible to restore a large proportion of the
total Demand so disconnected within a reasonable period of time, NGET may instruct a
Network Operator to implement additional Demand Disconnection manually, and restore an
equivalent amount of the Demand that had been disconnected automatically. The purpose of
such action is to ensure that a subsequent fall in Frequency will again be contained by the
operation of automatic low Frequency Demand Disconnection.
OC6.6.4
Once an automatic low Frequency Demand Disconnection has taken place, the Network
Operator on whose User System it has occurred, will not reconnect until NGET instructs that
Network Operator to do so in accordance with OC6.
OC6.6.5
Once the Frequency has recovered, each Network Operator will abide by the instructions of
NGET with regard to reconnection under OC6.6 without delay. Reconnection must be achieved
as soon as possible and the process of reconnection must begin within 2 minutes of the
instruction being given by NGET.
OC6.6.6
(a) Non-Embedded Customers (including a Pumped Storage Generator) must provide
automatic low Frequency disconnection, which will be split into discrete blocks.
(b) The number and size of blocks and the associated low Frequency settings will be as
specified by NGET by week 24 each calendar year following discussion with the NonEmbedded Customers (including a Pumped Storage Generator) in accordance with the
relevant Bilateral Agreement.
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OC6.6.7
(a) In addition, Generators may wish to disconnect Generating Units from the System, either
manually or automatically, should they be subject to Frequency levels which could result in
Generating Unit damage.
(b) This Disconnection facility on such Generating Unit directly connected to the National
Electricity Transmission System, will be agreed with NGET in accordance with the
Bilateral Agreement.
(c) Any Embedded Power Stations will need to agree this Disconnection facility with the
relevant User to whose System that Power Station is connected, which will then need to
notify NGET of this.
OC6.6.8
The Network Operator or Non-Embedded Customer, as the case may be, will notify NGET
with an estimation of the Demand reduction which has occurred under automatic low Frequency
Demand Disconnection and similarly notify the restoration, as the case may be, in each case
within five minutes of the Disconnection or restoration.
OC6.6.9
Pursuant to the provisions of OC1.5.6 the Network Operator and Non-Embedded Customer
will supply to NGET details of the amount of Demand reduction or restoration actually achieved.
OC6.6.10
(a) In the case of a User, it is not necessary for it to provide automatic low Frequency
disconnection under OC6.6 only to the extent that it is providing, at the time it would be so
needed, low Frequency disconnection at a higher level of Frequency as an Ancillary
Service, namely if the amount provided as an Ancillary Service is less than that required
under OC6.6 then the User must provide the balance required under OC6.6 at the time it is
so needed.
(b) The provisions of OC7.4.8 relating to the use of Demand Control should be borne in mind
by Users.
OC6.7
EMERGENCY MANUAL DISCONNECTION
OC6.7.1
Each Network Operator will make arrangements that will enable it, following an instruction from
NGET, to disconnect Customers on its User System under emergency conditions irrespective
of Frequency within 30 minutes. It must be possible to apply the Demand Disconnections to
individual or specific groups of Grid Supply Points, as determined by NGET.
OC6.7.2
(a) Each Network Operator shall provide NGET in writing by week 24 in each calendar year, in
respect of the next following year beginning week 24, on a Grid Supply Point basis, with
the following information (which is set out in a tabular format in the Appendix):
(i)
its total peak Demand (based on Annual ACS Conditions); and
(ii)
the percentage value of the total peak Demand that can be disconnected (and
must include that which can also be reduced by voltage reduction, where
applicable) within timescales of 5/10/15/20/25/30 minutes.
(b) The information should include, in relation to the first 5 minutes, as a minimum, the 20% of
Demand that must be reduced on instruction under OC6.5.
OC6.7.3
Each Network Operator will abide by the instructions of NGET with regard to Disconnection
under OC6.7 without delay, and the Disconnection must be achieved as soon as possible after
the instruction being given by NGET, and in any case, within the timescale registered in OC6.7.
The instruction may relate to an individual Grid Supply Point and/or groups of Grid Supply
Points.
OC6.7.4
NGET will notify a Network Operator who has been instructed under OC6.7, of what has
happened on the National Electricity Transmission System to necessitate the instruction, in
accordance with the provisions of OC7 and, if relevant, OC10.
OC6.7.5
Once a Disconnection has been applied by a Network Operator at the instruction of NGET,
that Network Operator will not reconnect until NGET instructs it to do so in accordance with
OC6.
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OC6.7.6
Each Network Operator will abide by the instructions of NGET with regard to reconnection
under OC6.7 without delay, and shall not reconnect until it has received such instruction and
reconnection must be achieved as soon as possible and the process of reconnection must begin
within 2 minutes of the instruction being given by NGET.
OC6.7.7
NGET may itself disconnect manually and reconnect Non-Embedded Customers as part of a
Demand Control requirement under emergency conditions.
OC6.7.8
If NGET determines that emergency manual Disconnection referred to in OC6.7 is inadequate,
NGET may disconnect Network Operators and/or Non-Embedded Customers at Grid Supply
Points, to preserve the security of the National Electricity Transmission System.
OC6.7.9
Pursuant to the provisions of OC1.5.6 the Network Operator will supply to NGET details of the
amount of Demand reduction or restoration actually achieved.
OC6.8
OPERATION OF THE BALANCING MECHANISM DURING DEMAND CONTROL
Demand Control will constitute an Emergency Instruction in accordance with BC2.9 and it
may be necessary to depart from normal Balancing Mechanism operation in accordance with
BC2 in issuing Bid-Offer Acceptances. NGET will inform affected BM Participants in
accordance with the provisions of OC7.
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APPENDIX 1 - EMERGENCY MANUAL DEMAND
REDUCTION/DISCONNECTION SUMMARY SHEET
(As set out in OC6.7)
NETWORK OPERATOR:
GRID
SUPPLY
POINT
[YEAR] PEAK:
% OF GROUP DEMAND DISCONNECTION
(AND/OR REDUCTION IN THE CASE OF
THE FIRST 5 MINUTES)
(CUMULATIVE)
PEAK
MW
REMARKS
TIME (MINS)
(Name)
5
10
15
20
25
30
Notes:
1.
Data to be provided annually by week 24 to cover the following year.
< END OF OPERATING CODE NO. 6 >
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OPERATING CODE NO. 7
(OC7)
OPERATIONAL LIAISON
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
OC7.1 INTRODUCTION...................................................................................................................................2
OC7.2 OBJECTIVE ..........................................................................................................................................2
OC7.3 SCOPE..................................................................................................................................................3
OC7.4 PROCEDURE .......................................................................................................................................3
OC7.4.5 Requirement To Notify Operations .............................................................................................3
OC7.4.6 Requirements To Notify Events..................................................................................................6
OC7.4.7 Significant Incidents....................................................................................................................9
Oc7.4.8 National Electricity Transmission System Warnings ...................................................................9
OC7.5 PROCEDURE IN RELATION TO INTEGRAL EQUIPMENT TESTS .................................................12
OC7.6 PROCEDURE IN RESPECT OF OPERATIONAL SWITCHING IN SCOTLAND AND
OFFSHORE......................................................................................................................................................14
APPENDIX 1 - NATIONAL ELECTRICITY TRANSMISSION SYSTEM WARNINGS TABLE .........................17
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OC7.1
INTRODUCTION
OC7.1.1
Operating Code No. 7 ("OC7") sets out the requirements for the exchange of information in
relation to Operations and/or Events on the Total System which have had (or may have had)
or will have (or may have) an Operational Effect:
(a) on the National Electricity Transmission System in the case of an Operation and/or
Event occurring on the System of a User or Users; and
(b) on the System of a User or Users in the case of an Operation and/or Event occurring on
the National Electricity Transmission System.
It also describes the types of National Electricity Transmission System Warning which may
be issued by NGET.
OC7.1.2
The requirement to notify in OC7 relates generally to notifying of what is expected to happen or
what has happened and not the reasons why. However, as OC7 provides, when an Event or
Operation has occurred on the National Electricity Transmission System which itself has
been caused by (or exacerbated by) an Operation or Event on a User's System, NGET in
reporting the Event or Operation on the National Electricity Transmission System to another
User can pass on what it has been told by the first User in relation to the Operation or Event on
the first User's System.
OC7.1.3
Where an Event or Operation on the National Electricity Transmission System falls to be
reported by NGET to an Externally Interconnected System Operator under an
Interconnection Agreement, OC7 provides that in the situation where that Event or Operation
has been caused by (or exacerbated by) an Operation or Event on a User's System, NGET
can pass on what it has been told by the User in relation to the Operation or Event on that
User's System.
OC7.1.4
OC7 also deals with Integral Equipment Tests.
OC7.1.5
To reconfigure the National Electricity Transmission System, NGET may reasonably require
the assistance of a User to reconfigure parts of the User System. To reconfigure its User
System a User may reasonably require the reasonable assistance of NGET to direct the
reconfiguration of parts of the National Electricity Transmission System.
OC7.1.6
OC7.6 sets down the arrangements for the exchange of information required when configuring
Connection Sites (or in the case of OTSUA operational prior to the OTSUA Transfer Time,
Transmission Interface Sites) and parts of the National Electricity Transmission System
adjacent to those Connection Sites (or Transmission Interface Sites) in Scotland and
Offshore. It also covers the setting up of a Local Switching Procedure. NGET shall procure
that Relevant Transmission Licensees shall comply with section OC7.6 and any relevant
Local Switching Procedure where and to the extent that such matters apply to them.
OC7.2
OBJECTIVE
The objectives of OC7 are:
OC7.2.1
To provide for the exchange of information so that the implications of an Operation and/or
Event can be considered, possible risks arising from it can be assessed and appropriate action
taken by the relevant party in order to maintain the integrity of the Total System. OC7 does not
seek to deal with any actions arising from the exchange of information, but merely with that
exchange.
OC7.2.2
To provide for types of National Electricity Transmission System Warnings which may be
issued by NGET.
OC7.2.3
To provide the framework for the information flow and discussion between NGET and certain
Users in relation to Integral Equipment Tests.
OC7.2.4
To provide the procedure to be followed in respect of Operational Switching in Scotland and
Offshore.
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OC7.3 SCOPE
OC7.3.1
OC7 applies to NGET and to Users, which in OC7 means:
(a) Generators (other than those which only have Embedded Small Power Stations or
Embedded Medium Power Stations) and including Generators undertaking OTSDUW;
(b) Network Operators;
(c) Non-Embedded Customers;
(d) Suppliers (for the purposes of National Electricity Transmission System Warnings);
(e) Externally Interconnected System Operators (for the purposes of National Electricity
Transmission System Warnings); and
(f)
DC Converter Station owners.
The procedure for operational liaison by NGET with Externally Interconnected System
Operators is set out in the Interconnection Agreement with each Externally Interconnected
System Operator.
In Scotland and Offshore OC7.6 also applies to Relevant Transmission Licensees.
OC7.4
PROCEDURE
OC7.4.1
The term "Operation" means a scheduled or planned action relating to the operation of a
System (including an Embedded Power Station).
OC7.4.2
The term "Event" means an unscheduled or unplanned (although it may be anticipated)
occurrence on, or relating to, a System (including an Embedded Power Station) including,
without limiting that general description, faults, incidents and breakdowns and adverse weather
conditions being experienced.
OC7.4.3
The term "Operational Effect" means any effect on the operation of the relevant other System
which causes the National Electricity Transmission System or the Systems of the other User
or Users, as the case may be, to operate (or be at a materially increased risk of operating)
differently to the way in which they would or may have normally operated in the absence of that
effect.
OC7.4.4
References in this OC7 to a System of a User or User's System shall not include Embedded
Small Power Stations or Embedded Medium Power Stations, unless otherwise stated.
OC7.4.5
Requirement To Notify Operations
OC7.4.5.1
Operation On The National Electricity Transmission System
In the case of an Operation on the National Electricity Transmission System, which will have
(or may have) an Operational Effect on the System(s) of a User or Users, NGET will notify the
User or Users whose System(s) will, or may, in the reasonable opinion of NGET, be affected, in
accordance with OC7.
OC7.4.5.2
Operation On A User's System
In the case of an Operation on the System of a User which will have (or may have) an
Operational Effect on the National Electricity Transmission System (including an equivalent
to an Operation on the equivalent of a System of a User or other person connected to that
User's System which, via that User System, will or may have an Operational Effect on the
National Electricity Transmission System), the User will notify NGET in accordance with OC7.
Following notification by the User, NGET will notify any other User or Users on whose
System(s) the Operation will have, or may have, in the reasonable opinion of NGET, an
Operational Effect, in accordance with OC7 and will notify any Externally Interconnected
System Operator on whose System the Operation will have, or may have, in the reasonable
opinion of NGET, an Operational Effect, if it is required to do so by the relevant
Interconnection Agreement.
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OC7.4.5.3
Examples Of Situations Where Notification By NGET Or A User May Be Required
Whilst in no way limiting the general requirement to notify in advance set out in OC7.4.5.1 and
OC7.4.5.2, the following are examples of situations where notification in accordance with
OC7.4.5 will be required if they will, or may, have an Operational Effect:
(a) the implementation of a planned outage of Plant and/or Apparatus which has been
arranged pursuant to OC2;
(b) the operation (other than, in the case of a User, at the instruction of NGET) of any circuit
breaker or isolator/disconnector or any sequence or combination of the two; or
(c) voltage control.
OC7.4.5.4
Operations Caused By Another Operation Or By An Event
An Operation may be caused by another Operation or an Event on another's System
(including an Embedded Power Station) (or by the equivalent of an Event or Operation on the
System of an Externally Interconnected System Operator or Interconnector User) and in
that situation the information to be notified is different to that where the Operation arose
independently of any other Operation or Event, as more particularly provided in OC7.4.5.6.
OC7.4.5.5
Form
A notification and any response to any questions asked under OC7.4.5, of an Operation which
has arisen independently of any other Operation or of an Event, shall be of sufficient detail to
describe the Operation (although it need not state the cause) and to enable the recipient of the
notification reasonably to consider and assess the implications and risks arising (provided that, in
the case of an Operation on a User's System which NGET is notifying to other Users under
OC7.4.5.2, NGET will only pass on what it has been told by the User which has notified it) and
will include the name of the individual reporting the Operation on behalf of NGET or the User, as
the case may be. The recipient may ask questions to clarify the notification and the giver of the
notification will, insofar as it is able, answer any questions raised, provided that, in the case of an
Operation on a User's System which NGET is notifying to other Users under OC7.4.5.2, in
answering any question, NGET will not pass on anything further than that which it has been told
by the User which has notified it. NGET may pass on the information contained in the notification
as provided in OC7.4.5.6.
OC7.4.5.6
(a) A notification by NGET of an Operation under OC7.4.5.1 which has been caused by
another Operation (the "first Operation") or by an Event on a User's System, will describe
the Operation and will contain the information which NGET has been given in relation to the
first Operation or that Event by the User. The notification and any response to any
questions asked (other than in relation to the information which NGET is merely passing on
from a User) will be of sufficient detail to enable the recipient of the notification reasonably
to consider and assess the implications and risks arising from the Operation on the
National Electricity Transmission System and will include the name of the individual
reporting the Operation on behalf of NGET. The recipient may ask questions to clarify the
notification and NGET will, insofar as it is able, answer any questions raised, provided that
in relation to the information which NGET is merely passing on from a User, in answering
any question NGET will not pass on anything further than that which it has been told by the
User which has notified it.
(b) Where a User is reporting an Operation or an Event which itself has been caused by an
incident or scheduled or planned action affecting (but not on) its System, the notification to
NGET will contain the information which the User has been given by the person connected
to its System in relation to that incident or scheduled or planned action (which the User
must require, contractually or otherwise, the person connected to its System to give to it)
and NGET may pass on the information contained in the notification as provided in this
OC7.4.5.6.
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OC7.4.5.7
Where an Operation on the National Electricity Transmission System falls to be reported by
NGET under an Interconnection Agreement and the Operation has been caused by another
Operation (the "first Operation") or by an Event on a User's System, NGET will include in that
report the information which NGET has been given in relation to the first Operation or that Event
by the User (including any information relating to an incident or scheduled or planned action, as
provided in OC7.4.5.6).
OC7.4.5.8
(a) A notification to a User by NGET of an Operation under OC7.4.5.1 which has been caused
by the equivalent of an Operation or of an Event on the equivalent of a System of an
Externally Interconnected System Operator or Interconnector User, will describe the
Operation on the National Electricity Transmission System and will contain the
information which NGET has been given, in relation to the equivalent of an Operation or of
an Event on the equivalent of a System of an Externally Interconnected System
Operator or Interconnector User, by that Externally Interconnected System Operator
or Interconnector User.
(b) The notification and any response to any question asked (other than in relation to the
information which NGET is merely passing on from that Externally Interconnected
System Operator or Interconnector User) will be of sufficient detail to enable the recipient
of the notification reasonably to consider and assess the implications and risks arising from
the Operation on the National Electricity Transmission System and will include the
name of the individual reporting the Operation on behalf of NGET. The recipient may ask
questions to clarify the notification and NGET will, insofar as it is able, answer any questions
raised, provided that, in relation to the information which NGET is merely passing on from
an Externally Interconnected System Operator or Interconnector User, in answering
any question NGET will not pass on anything further than that which it has been told by the
Externally Interconnected System Operator or Interconnector User which has notified
it.
OC7.4.5.9
(a) A Network Operator may pass on the information contained in a notification to it from
NGET under OC7.4.5.1, to a Generator with a Generating Unit or a Power Park Module
connected to its System, or to a DC Converter Station owner with a DC Converter
connected to its System, or to the operator of another User System connected to its
System (which, for the avoidance of doubt, could be another Network Operator), in
connection with reporting the equivalent of an Operation under the Distribution Code (or
the contract pursuant to which that Generating Unit or Power Park Module or other User
System, or to a DC Converter Station is connected to the System of that Network
Operator) (if the Operation on the National Electricity Transmission System caused it).
(b) A Generator may pass on the information contained in a notification to it from NGET under
OC7.4.5.1, to another Generator with a Generating Unit or a Power Park Module
connected to its System, or to the operator of a User System connected to its System
(which, for the avoidance of doubt, could be a Network Operator), if it is required (by a
contract pursuant to which that Generating Unit or that Power Park Module or that User
System is connected to its System) to do so in connection with the equivalent of an
Operation on its System (if the Operation on the National Electricity Transmission
System caused it).
OC7.4.5.10
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(a) Other than as provided in OC7.4.5.9, a Network Operator or a Generator may not pass on
any information contained in a notification to it from NGET under OC7.4.5.1 (and an
operator of a User System or Generator receiving information which was contained in a
notification to a Generator or a Network Operator, as the case may be, from NGET under
OC7.4.5.1, as envisaged in OC7.4.5.9 may not pass on this information) to any other
person, but may inform persons connected to its System (or in the case of a Generator
which is also a Supplier, inform persons to which it supplies electricity which may be
affected) that there has been an incident on the Total System, the general nature of the
incident (but not the cause of the incident) and (if known and if power supplies have been
affected) an estimated time of return to service.
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(b) In the case of a Generator which has an Affiliate which is a Supplier, the Generator may
inform it that there has been an incident on the Total System, the general nature of the
incident (but not the cause of the incident) and (if known and if power supplies have been
affected in a particular area) an estimated time of return to service in that area, and that
Supplier may pass this on to persons to which it supplies electricity which may be affected).
(c) Each Network Operator and Generator shall use its reasonable endeavours to procure
that any Generator or operator of a User System receiving information which was
contained in a notification to a Generator or Network Operator, as the case may be, from
NGET under OC7.4.5.1, which is not bound by the Grid Code, does not pass on any
information other than as provided above.
OC7.4.5.11
The notification will, if either party requests, be recorded by the sender and dictated to the
recipient, who shall record and repeat each phrase as it is received and on completion of the
dictation shall repeat back the notification in full to the sender who shall confirm that it has been
accurately recorded.
OC7.4.5.12
Timing
A notification under OC7.4.5 will be given as far in advance as possible and in any event shall be
given in sufficient time as will reasonably allow the recipient to consider and assess the
implications and risks arising.
OC7.4.6
Requirements To Notify Events
OC7.4.6.1
Events On The National Electricity Transmission System
In the case of an Event on the National Electricity Transmission System which has had (or
may have had) an Operational Effect on the System(s) of a User or Users, NGET will notify
the User or Users whose System(s) have been, or may have been, in the reasonable opinion of
NGET, affected, in accordance with OC7.
OC7.4.6.2
Events On A User's System
In the case of an Event on the System of a User which has had (or may have had) an
Operational Effect on the National Electricity Transmission System, the User will notify
NGET in accordance with OC7.
OC7.4.6.3
Events Caused By Another Event Or By An Operation
An Event may be caused (or exacerbated by) another Event or by an Operation on another's
System (including on an Embedded Power Station) (or by the equivalent of an Event or
Operation on the equivalent of a System of an Externally Interconnected System Operator or
Interconnector User) and in that situation the information to be notified is different to that where
the Event arose independently of any other Event or Operation, as more particularly provided in
OC7.4.6.7.
OC7.4.6.4
NGET or a User, as the case may be, may enquire of the other whether an Event has occurred
on the other's System. If it has, and the party on whose System the Event has occurred is of the
opinion that it may have had an Operational Effect on the System of the party making the
enquiry, it shall notify the enquirer in accordance with OC7.
OC7.4.6.5
Examples Of Situations Where Notification By NGET Or A User May Be Required
Whilst in no way limiting the general requirement to notify set out in OC7.4.6.1, OC7.4.6.2 and
OC7.4.6.3, the following are examples of situations where notification in accordance with
OC7.4.6 will be required if they have an Operational Effect:
(a) where Plant and/or Apparatus is being operated in excess of its capability or may present
a hazard to personnel;
(b) the activation of any alarm or indication of any abnormal operating condition;
(c) adverse weather conditions being experienced;
(d) breakdown of, or faults on, or temporary changes in the capabilities of, Plant and/or
Apparatus;
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(e) breakdown of, or faults on, control, communication and metering equipment; or
(f)
increased risk of inadvertent protection operation.
Form
OC7.4.6.6
A notification and any response to any questions asked under OC7.4.6.1 and OC7.4.6.2 of an
Event which has arisen independently of any other Event or of an Operation, will describe the
Event, although it need not state the cause of the Event, and, subject to that, will be of sufficient
detail to enable the recipient of the notification reasonably to consider and assess the
implications and risks arising and will include the name of the individual reporting the Event on
behalf of NGET or the User, as the case may be. The recipient may ask questions to clarify the
notification and the giver of the notification will, insofar as it is able (although it need not state the
cause of the Event) answer any questions raised. NGET may pass on the information contained
in the notification as provided in OC7.4.6.7.
OC7.4.6.7
(a) A notification (and any response to any questions asked under OC7.4.6.1) by NGET of (or
relating to) an Event under OC7.4.6.1 which has been caused by (or exacerbated by)
another Event (the "first Event") or by an Operation on a User's System will describe the
Event and will contain the information which NGET has been given in relation to the first
Event or that Operation by the User (but otherwise need not state the cause of the Event).
The notification and any response to any questions asked (other than in relation to the
information which NGET is merely passing on from a User) will be of sufficient detail to
enable the recipient of the notification reasonably to consider and assess the implications
and risks arising from the Event on the National Electricity Transmission System and
will include the name of the individual reporting the Event on behalf of NGET. The recipient
may ask questions to clarify the notification and NGET will, insofar as it is able, answer any
questions raised, provided that in relation to the information which NGET is merely passing
on from a User, in answering any question NGET will not pass on anything further than that
which it has been told by the User which has notified it.
(b) Where a User is reporting an Event or an Operation which itself has been caused by (or
exacerbated by) an incident or scheduled or planned action affecting (but not on) its
System the notification to NGET will contain the information which the User has been given
by the person connected to its System in relation to that incident or scheduled or planned
action (which the User must require, contractually or otherwise, the person connected to its
System to give to it) and NGET may pass on the information contained in the notification as
provided in this OC7.4.6.7.
OC7.4.6.8
Where an Event on the National Electricity Transmission System falls to be reported by
NGET under an Interconnection Agreement and the Event has been caused by (or
exacerbated by) another Event (the "first Event") or by an Operation on a User's System,
NGET will include in that report the information which NGET has been given in relation to the first
Event or that Operation by the User (including any information relating to an incident or
scheduled or planned action on that User's System, as provided in OC7.4.6.7).
OC7.4.6.9
(a) A notification to a User (and any response to any questions asked under OC7.4.6.1) by
NGET of (or relating to) an Event under OC7.4.6.1 which has been caused by (or
exacerbated by) the equivalent of an Event or of an Operation on the equivalent of a
System of an Externally Interconnected System Operator or Interconnector User, will
describe the Event on the National Electricity Transmission System and will contain the
information which NGET has been given, in relation to the equivalent of an Event or of an
Operation on the equivalent of a System of an Externally Interconnected System
Operator or Interconnector User, by that Externally Interconnected System Operator
or Interconnector User (but otherwise need not state the cause of the Event).
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(b) The notification and any response to any questions asked (other than in relation to the
information which NGET is merely passing on from that Externally Interconnected
System Operator or Interconnector User) will be of sufficient detail to enable the recipient
of the notification reasonably to consider and assess the implications and risks arising from
the Event on the National Electricity Transmission System and will include the name of
the individual reporting the Event on behalf of NGET. The recipient may ask questions to
clarify the notification and NGET will, insofar as it is able (although it need not state the
cause of the Event) answer any questions raised, provided that, in relation to the
information which NGET is merely passing on from an Externally Interconnected System
Operator or Interconnector User, in answering any question NGET will not pass on
anything further than that which it has been told by the Externally Interconnected System
Operator or Interconnector User which has notified it.
OC7.4.6.10
(a) A Network Operator may pass on the information contained in a notification to it from
NGET under OC7.4.6.1, to a Generator with a Generating Unit or a Power Park Module
connected to its System or to a DC Converter Station owner with a DC Converter
connected to its System or to the operator of another User System connected to its
System (which, for the avoidance of doubt, could be a Network Operator), in connection
with reporting the equivalent of an Event under the Distribution Code (or the contract
pursuant to which that Generating Unit or Power Park Module or DC Converter or other
User System is connected to the System of that Network Operator) (if the Event on the
National Electricity Transmission System caused or exacerbated it).
(b) A Generator may pass on the information contained in a notification to it from NGET under
OC7.4.6.1, to another Generator with a Generating Unit or a Power Park Module
connected to its System or to the operator of a User System connected to its System
(which, for the avoidance of doubt, could be a Network Operator), if it is required (by a
contract pursuant to which that Generating Unit or that Power Park Module or that User
System is connected to its System) to do so in connection with the equivalent of an Event
on its System (if the Event on the National Electricity Transmission System caused or
exacerbated it).
OC7.4.6.11
(a) Other than as provided in OC7.4.6.10, a Network Operator or a Generator, may not pass
on any information contained in a notification to it from NGET under OC7.4.6.1 (and an
operator of a User System or Generator receiving information which was contained in a
notification to a Generator or a Network Operator, as the case may be, from NGET under
OC7.4.6.1, as envisaged in OC7.4.6.10 may not pass on this information) to any other
person, but may inform persons connected to its System (or in the case of a Generator
which is also a Supplier, inform persons to which it supplies electricity which may be
affected) that there has been an incident on the Total System, the general nature of the
incident (but not the cause of the incident) and (if known and if power supplies have been
affected) an estimated time of return to service.
(b) In the case of a Generator which has an Affiliate which is a Supplier, the Generator may
inform it that there has been an incident on the Total System, the general nature of the
incident (but not the cause of the incident) and (if known and if power supplies have been
affected in a particular area) an estimated time of return to service in that area, and that
Supplier may pass this on to persons to which it supplies electricity which may be affected).
(c) Each Network Operator and Generator shall use its reasonable endeavours to procure
that any Generator or operator of a User System receiving information which was
contained in a notification to a Generator or Network Operator, as the case may be, from
NGET under OC7.4.6.1, which is not bound by the Grid Code, does not pass on any
information other than as provided above.
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OC7.4.6.12
When an Event relating to a Generating Unit, a Power Park Module or a DC Converter (or
OTSUA operational prior to the OTSUA Transfer Time), has been reported to NGET by a
Generator or DC Converter Station owner under OC7.4.6 and it is necessary in order for the
Generator or DC Converter Station owner to assess the implications of the Event on its
System more accurately, the Generator or DC Converter Station owner may ask NGET for
details of the fault levels from the National Electricity Transmission System to that
Generating Unit, Power Park Module or DC Converter (or OTSUA operational prior to the
OTSUA Transfer Time) at the time of the Event, and NGET will, as soon as reasonably
practicable, give the Generator or DC Converter Station owner that information provided that
NGET has that information.
OC7.4.6.13
Except in an emergency situation the notification of an Event will, if either party requests, be
recorded by the sender and dictated to the recipient, who shall record and repeat each phrase as
it is received and on completion of the dictation shall repeat the notification in full to the sender
who shall confirm that it has been accurately recorded.
Timing
OC7.4.6.14
A notification under OC7.4.6 shall be given as soon as possible after the occurrence of the
Event, or time that the Event is known of or anticipated by the giver of the notification under
OC7, and in any event within 15 minutes of such time.
OC7.4.7
Significant Incidents
OC7.4.7.1
Where a User notifies NGET of an Event under OC7 which NGET considers has had or may
have had a significant effect on the National Electricity Transmission System, NGET will
require the User to report that Event in writing in accordance with the provisions of OC10 and
will notify that User accordingly.
OC7.4.7.2
Where NGET notifies a User of an Event under OC7 which the User considers has had or may
have had a significant effect on that User's System, that User will require NGET to report that
Event in writing in accordance with the provisions of OC10 and will notify NGET accordingly.
OC7.4.7.3
Events which NGET requires a User to report in writing pursuant to OC7.4.7.1, and Events
which a User requires NGET to report in writing pursuant to OC7.4.7.2, are known as
"Significant Incidents".
OC7.4.7.4
Without limiting the general description set out in OC7.4.7.1 and OC7.4.7.2, a Significant
Incident will include Events having an Operational Effect which result in, or may result in, the
following:
(a) operation of Plant and/or Apparatus either manually or automatically;
(b) voltage outside statutory limits;
(c) Frequency outside statutory limits; or
(d) System instability.
OC 7.4.8
National Electricity Transmission System Warnings
OC7.4.8.1
Role Of National Electricity Transmission System Warnings
National Electricity Transmission System Warnings as described below provide information
relating to System conditions or Events and are intended to:
(i)
alert Users to possible or actual Plant shortage, System problems and/or Demand
reductions;
(ii)
inform of the applicable period;
(iii) indicate intended consequences for Users; and
(iv) enable specified Users to be in a state of readiness to react properly to instructions
received from NGET.
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A table of National Electricity Transmission System Warnings, set out in the Appendix to
OC7, summarises the warnings and their usage. In the case of a conflict between the table and
the provisions of the written text of OC7, the written text will prevail.
OC7.4.8.2
Recipients Of National Electricity Transmission System Warnings
(a) Where National Electricity Transmission System Warnings,(except those relating to
Demand Control Imminent), are applicable to System conditions or Events which have
widespread effect, NGET will notify all Users under OC7.
(b) Where in NGET’s judgement System conditions or Events may only have a limited effect,
the National Electricity Transmission System Warning will only be issued to those
Users who are or may in NGET’s judgement be affected.
(c) Where a National Electricity Transmission System Warning - Demand Control
Imminent is issued it will only be sent to those Users who are likely to receive Demand
Control instructions from NGET.
OC7.4.8.3
Preparatory Action
(a) Where possible, and if required, recipients of the warnings should take such preparatory
action as they deem necessary taking into account the information contained in the
National Electricity Transmission System Warning. All warnings will be of a form
determined by NGET and will remain in force from the stated time of commencement until
the cancellation, amendment or re-issue, as the case may be, is notified by NGET.
(b) Where a National Electricity Transmission System Warning has been issued to a
Network Operator and is current, Demand Control should not (subject as provided below)
be employed unless instructed by NGET. If Demand Control is, however, necessary to
preserve the integrity of the Network Operator's System, then the impact upon the
integrity of the Total System should be considered by the Network Operator and where
practicable discussed with NGET prior to its implementation.
Where a National Electricity Transmission System Warning has been issued to a
Supplier, further Customer Demand Management (in addition to that previously notified
under OC1 - Demand Forecasts) must only be implemented following notification to NGET.
(c) National Electricity Transmission System Warnings will be issued by such data
transmission facilities as have been agreed between NGET and Users. In the case of
Generators with Gensets this will normally be at their Trading Points (if they have notified
NGET that they have a Trading Point).
(d) Users may at times be informed by telephone of National Electricity Transmission
System Warnings and in these circumstances confirmation will be sent to those Users so
notified by such data transmission facilities as have been agreed between NGET and
Users, as soon as possible.
OC7.4.8.4
Types Of National Electricity Transmission System Warnings
National Electricity Transmission System Warnings consist of the following types:(i)
National Electricity Transmission System Warning - Electricity Margin Notice
(ii)
National Electricity Transmission System Warning - High Risk of Demand Reduction
(iii) National Electricity Transmission System Warning - Demand Control Imminent
(iv) National Electricity Transmission System Warning - Risk of System Disturbance
OC7.4.8.5
National Electricity Transmission System Warning - Electricity Margin Notice
A National Electricity Transmission System Warning - Electricity Margin Notice may be
issued to Users in accordance with OC7.4.8.2, at times when there is a reduced System
Margin, as determined under BC1.5.4. It will contain the following information:
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(i)
the period for which the warning is applicable; and
(ii)
the availability shortfall in MW; and
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(iii) intended consequences for Users, including notification that Maximum Generation
Service may be instructed.
OC 7.4.8.6
National Electricity Transmission System Warning - High Risk of Demand Reduction
(a) A National Electricity Transmission System Warning - High Risk of Demand
Reduction may be issued to Users in accordance with OC7.4.8.2 at times when there is a
reduced System Margin, as determined under BC1.5.4 and in NGET’s judgement there is
increased risk of Demand reduction being implemented under OC6.5.1. It will contain the
following information in addition to the required information in a National Electricity
Transmission System Warning - Electricity Margin Notice:
(i)
the possible percentage level of Demand reduction required; and
(ii)
Specify those Network Operators and Non Embedded Customers who may
subsequently receive instructions under OC6.5.1.
(b) A National Electricity Transmission System Warning - High Risk of Demand
Reduction may also be issued by NGET to those Network Operators and Non
Embedded Customers who may subsequently receive instructions under OC6.5.1 relating
to a Demand reduction in circumstances not related to System Margin (for example
Demand reduction required to manage System overloading).
The National Electricity Transmission System Warning - High Risk of Demand
Reduction will specify the period during which Demand reduction may be required and the
part of the Total System to which it applies and any other matters specified in OC6.5.
OC7.4.8.6.1
Protracted Periods Of Generation Shortage
(a) Whenever NGET anticipates that a protracted period of generation shortage may exist a
National Electricity Transmission System Warning - Electricity Margin Notice or High
Risk of Demand Reduction may be issued, to give as much notice as possible to those
Network Operators and Non Embedded Customers who may subsequently receive
instructions under OC6.5.
(b) A National Electricity Transmission System Warning - High Risk of Demand
Reduction will in these instances include an estimate of the percentage of Demand
reduction that may be required and the anticipated duration of the Demand reduction. It
may also include information relating to estimates of any further percentage of Demand
reduction that may be required.
(c) The issue of the National Electricity Transmission System Warning - Electricity Margin
Notice or High Risk of Demand Reduction is intended to enable recipients to plan ahead
on the various aspects of Demand reduction.
OC7.4.8.7
National Electricity Transmission System Warning - Demand Control Imminent
(a) A National Electricity Transmission System Warning - Demand Control Imminent,
relating to a Demand reduction under OC6.5, will be issued by NGET to Users in
accordance with OC7.4.8.2. It will specify those Network Operators who may subsequently
receive instructions under OC6.5.
(b) A National Electricity Transmission System Warning - Demand Control Imminent,
need not be preceded by any other National Electricity Transmission System Warning
and will be issued when a Demand reduction is expected within the following 30 minutes,
but will not cease to have effect after 30 minutes from its issue. However, NGET will either
reissue the National Electricity Transmission System Warning - Demand Control
Imminent or cancel the National Electricity Transmission System Warning - Demand
Control Imminent no later than 2 hours from first issue, or from re-issue, as the case may
be.
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OC7.4.8.8
National Electricity Transmission System Warning - Risk of System Disturbance
(a) A National Electricity Transmission System Warning - Risk of System Disturbance will
be issued by NGET to Users who may be affected when NGET knows there is a risk of
widespread and serious disturbance to the whole or part of, the National Electricity
Transmission System;
(b) The National Electricity Transmission System Warning - Risk of System Disturbance
will contain such information as NGET deems appropriate;
(c) for the duration of the National Electricity Transmission System Warning - Risk of
System Disturbance, each User in receipt of the National Electricity Transmission
System Warning - Risk of System Disturbance shall take the necessary steps to warn its
operational staff and to maintain its Plant and/or Apparatus in the condition in which it is
best able to withstand the anticipated disturbance;
(d) During the period that the National Electricity Transmission System Warning - Risk of
System Disturbance is in effect, NGET may issue Emergency Instructions in
accordance with BC2 and it may be necessary to depart from normal Balancing
Mechanism operation in accordance with BC2 in issuing Bid-Offer Acceptances.
OC7.4.8.9
Cancellation of National Electricity Transmission System Warning
(a) NGET will give notification of a Cancellation of National Electricity Transmission
System Warning to all Users issued with the National Electricity Transmission System
Warning when in NGET’s judgement System conditions have returned to normal.
(b) A Cancellation of National Electricity Transmission System Warning will identify the
type of National Electricity Transmission System Warning being cancelled and the
period for which it was issued. The Cancellation of National Electricity Transmission
System Warning will also identify any National Electricity Transmission System
Warnings that are still in force.
OC7.4.8.10
General Management Of National Electricity Transmission System Warnings
(a) National Electricity Transmission System Warnings remain in force for the period
specified unless superseded or cancelled by NGET.
(b) A National Electricity Transmission System Warning issued for a particular period may
be superseded by further related warnings. This will include National Electricity
Transmission System Warning - Electricity Margin Notice being superseded by
National Electricity Transmission System Warning - High Risk of Demand Reduction
and vice-versa.
(c) In circumstances where it is necessary for the period of a National Electricity
Transmission System Warning to be changed:
(i)
the period applicable may be extended by the issue of a National Electricity
Transmission System Warning with a period which follows on from the original
period, or
(ii)
revised or updated National Electricity Transmission System Warnings will be
issued where there is an overlap with the period specified in an existing National
Electricity Transmission System Warning, but only if the revised period also
includes the full period of the existing National Electricity Transmission System
Warning.
In any other case the existing National Electricity Transmission System Warning will be
cancelled and a new one issued.
(d) A National Electricity Transmission System Warning is no longer applicable once the
period has passed and to confirm this NGET will issue a Cancellation of National
Electricity Transmission System Warning.
OC7.5
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PROCEDURE IN RELATION TO INTEGRAL EQUIPMENT TESTS
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OC7.5.1
This section of the Grid Code deals with Integral Equipment Tests. It is designed to provide a
framework for the exchange of relevant information and for discussion between NGET and
certain Users in relation to Integral Equipment Tests.
OC7.5.2
An Integral Equipment Test :
(a) is carried out in accordance with the provisions of this OC7.5 at:
(i)
a User Site,
(ii)
a Transmission Site,
(iii) an Embedded Large Power Station, or,
(iv) an Embedded DC Converter Station;
(b) will normally be undertaken during commissioning or re-commissioning of Plant and/or
Apparatus;
(c) may, in the reasonable judgement of the person wishing to perform the test, cause, or have
the potential to cause, an Operational Effect on a part or parts of the Total System but
which with prior notice is unlikely to have a materially adverse effect on any part of the Total
System; and
(d) may form part of an agreed programme of work.
In the case of OTSUA operational prior to the OTSUA Transfer Time, a User’s Site or
Transmission Site shall, for the purposes of this OC7, include a site at which there is an
Interface Point until the OTSUA Transfer Time and the provisions of this OC7.5 and references
to OTSUA shall be construed and applied accordingly until the OTSUA Transfer Time.
OC7.5.3
A set of guidance notes is available from NGET on request, which provide further details on
suggested procedures, information flows and responsibilities.
Notification Of An IET
OC7.5.4
In order to undertake an Integral Equipment Test (and subject to OC7.5.8 below), the User or
NGET, as the case may be, (the proposer) must notify the other (the recipient) of a proposed
IET. Reasonable advance notification must be given, taking into account the nature of the test
and the circumstances which make the test necessary. This will allow recipients time to
adequately assess the impact of the IET on their System.
OC7.5.5
The notification of the IET must normally include the following information:(a) the proposed date and time of the IET;
(b) the name of the individual and the organisation proposing the IET;
(c) a proposed programme of testing; and
(d) such further detail as the proposer reasonably believes the recipient needs in order to
assess the effect the IET may have on relevant Plant and/or Apparatus.
OC7.5.6
In the case of an IET in connection with commissioning or re-commissioning, the test should be
incorporated as part of any overall commissioning programme agreed between NGET and the
User.
Response To Notification Of An IET
OC7.5.7
The recipient of notification of an IET must respond within a reasonable timescale prior to the
start time of the IET and will not unreasonably withhold or delay acceptance of the IET proposal.
OC7.5.8
(a) Where NGET receives notification of a proposed IET from a User, NGET will consult those
other Users whom it reasonably believes may be affected by the proposed IET to seek their
views. Information relating to the proposed IET may be passed on by NGET with the prior
agreement of the proposer. However it is not necessary for NGET to obtain the agreement
of any such User as IETs should not involve the application of irregular, unusual or extreme
conditions. NGET may however consider any comments received when deciding whether or
not to agree to an IET.
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(b) In the case of an Embedded Large Power Station or Embedded DC Converter Station,
the Generator or DC Converter Station owner as the case may be must liaise with both
NGET and the relevant Network Operator. NGET will not agree to an IET relating to such
Plant until the Generator or DC Converter Station owner has shown that it has the
agreement of the relevant Network Operator.
(c) A Network Operator will liaise with NGET as necessary in those instances where it is
aware of an Embedded Small Power Station or an Embedded Medium Power Station
which intends to perform tests which in the reasonable judgement of the Network Operator
may cause an Operational Effect on the National Electricity Transmission System.
OC7.5.9
The response from the recipient, following notification of an IET must be one of the following:
(a) to accept the IET proposal;
(b) to accept the IET proposal conditionally subject to minor modifications such as date and
time;
(c) not to agree the IET, but to suggest alterations to the detail and timing of the IET that are
necessary to make the IET acceptable.
Final Confirmation Of An IET
OC7.5.10
The date and time of an IET will be confirmed between NGET and the User, together with any
limitations and restrictions on operation of Plant and/or Apparatus.
OC7.5.11
The IET may subsequently be amended following discussion and agreement between NGET and
the User.
Carrying Out An IET
OC7.5.12
IETs may only take place when agreement has been reached and must be carried out in
accordance with the agreed programme of testing.
OC7.5.13
The implementation of an IET will be notified in accordance with OC7.4.5.
OC7.5.14
Where elements of the programme of testing change during the IET, there must be discussion
between the appropriate parties to identify whether the IET should continue.
OC7.6
PROCEDURE IN RESPECT OF OPERATIONAL SWITCHING IN SCOTLAND AND
OFFSHORE
OC7.6.1
This section OC7.6 of the Grid Code sets out the procedure to be followed for Operational
Switching in Scotland and Offshore. Its provisions are supplementary to the provisions of the
rest of this OC7.
It is designed to set down the arrangements for NGET, Users and the Relevant Transmission
Licensees in respect of the Operational Switching of Plant and Apparatus at a Connection
Site and parts of the National Electricity Transmission System adjacent to that Connection
Site.
OC7.6.2
In general:
(i)
NGET is responsible for directing the configuration of the National Electricity
Transmission System
(ii)
Each Relevant Transmission Licensee is responsible for the instruction and operation of
its Plant and Apparatus on its Transmission System
(iii) Each User is responsible for the configuration, instruction and operation of its Plant and
Apparatus.
Definitive schedules of these responsibilities for each Connection Site are contained in the
relevant Site Responsibility Schedules.
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For the avoidance of doubt, where a User operates Transmission Plant and Apparatus on
behalf of a Relevant Transmission Licensee, NGET cannot instruct the User to operate that
Plant and Apparatus.
Planned Operational Switching
OC7.6.3
Following the notification of an Operation under OC7.4.5, NGET and the User shall discuss the
Operational Switching required. NGET will then discuss and agree the details of the
Operational Switching with the Relevant Transmission Licensee. The Relevant
Transmission Licensee shall then make contact with the User to initiate the Operational
Switching. For the avoidance of doubt, from the time that the Relevant Transmission
Licensee makes contact with the User, the Relevant Transmission Licensee shall then
become the primary point of operational contact with the User in relation to OC7 for matters
which would or could affect, or would or could be affected by the Operational Switching.
OC7.6.4
The User shall be advised by the Relevant Transmission Licensee on the completion of the
Operational Switching, that NGET shall again become the primary point of operational contact
for the User in relation to OC7.
OC7.6.5
During Operational Switching, either the Relevant Transmission Licensee or the User may
need to unexpectedly terminate the Operational Switching. NGET may also need to terminate
the Operational Switching during the Operational Switching. In the event of unexpected
termination of the Operational Switching, NGET shall become the primary point of operational
contact for the User in relation to OC7. Following the termination of the Operational Switching,
it will not be permitted to restart that Operational Switching without the parties again following
the process described in OC7.6.3.
Emergencies
OC7.6.6
For Operations and/or Events that present an immediate hazard to the safety of personnel,
Plant or Apparatus, the Relevant Transmission Licensee may:
(i)
as permitted by the STC, carry out Operational Switching of Plant and Apparatus on its
Transmission System without reference to NGET and the User, and
(ii)
request a User to carry out Operational Switching without the User first receiving
notification from NGET.
In such emergency circumstances, communication between the Relevant Transmission
Licensee and the User shall normally be by telephone and will include an exchange of names.
The User shall use all reasonable endeavours to carry out Operational Switching on its Plant
and Apparatus without delay. Following completion of the requested Operational Switching,
the Relevant Transmission Licensee shall notify NGET of the Operational Switching which
has taken place. In such emergency circumstances, the User may only refuse to carry out
Operational Switching on safety grounds (relating to personnel or plant) and this must be
notified to the Relevant Transmission Licensee immediately by telephone.
OC7.6.7
For Operations and/or Events that present an immediate hazard to the safety of personnel,
Plant or Apparatus, and which require Operational Switching of Plant or Apparatus on a
Transmission System in order to remove the hazard, the User should contact the Relevant
Transmission Licensee directly to request Operational Switching of Plant or Apparatus on
its Transmission System.
In such emergency circumstances, communication between the Relevant Transmission
Licensee and the User shall normally be by telephone and will include an exchange of names.
The Relevant Transmission Licensee shall use all reasonable endeavours to carry out
Operational Switching on its Plant and Apparatus without delay. Following completion of the
requested Operational Switching, the User shall notify NGET of the Operational Switching
which has taken place. In such emergency circumstances, the Relevant Transmission
Licensee may only refuse to carry out Operational Switching on safety grounds (relating to
personnel or plant) and this must be notified to the User immediately by telephone.
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OC7.6.8
Establishment Of A Local Switching Procedure
(a) NGET, a User or a Relevant Transmission Licensee may reasonably require a Local
Switching Procedure to be established.
(b) Where the need for a Local Switching Procedure arises the following provisions shall
apply:
(i)
NGET, User(s) and the Relevant Transmission Licensee will discuss and agree
the detail of the Local Switching Procedure as soon as the requirement for a
Local Switching Procedure is identified. NGET will notify the Relevant
Transmission Licensee and the affected User(s) and will initiate these
discussions.
(ii)
Each Local Switching Procedure shall be in relation to either one or more
Connection Sites (or in the case of OTSUA operational prior to the OTSUA
Transfer Time, Transmission Interface Sites) and parts of the National
Electricity Transmission System adjacent to the Connection Site(s) (or in the
case of OTSUA operational prior to the OTSUA Transfer Time, Transmission
Interface Sites)
(iii) A draft Local Switching Procedure shall be prepared by the Relevant
Transmission Licensee to reflect the agreement reached and shall be sent to
NGET.
(iv) When a Local Switching Procedure has been prepared, it shall be sent by NGET
to the Relevant Transmission Licensee and User(s) for confirmation of its
accuracy.
(v) The Local Switching Procedure shall then be signed on behalf of NGET and on
behalf of each User and Relevant Transmission Licensee by way of written
confirmation of its accuracy.
(vi) Once agreed under this OC7.6.8, the procedure will become a Local Switching
Procedure under the Grid Code, and (subject to any change pursuant to this OC7)
will apply between NGET, Relevant Transmission Licensee and the relevant
User(s) as if it were part of the Grid Code.
(vii) Once signed, NGET will send a copy of the Local Switching Procedure to the
Relevant Transmission Licensee and the User(s).
(viii) An agreed Local Switching Procedure should be referenced by relevant Site
Responsibility Schedules.
(ix) NGET, the User(s) and the Relevant Transmission Licensee must make the
Local Switching Procedure readily available to the relevant operational staff.
(x) If the Relevant Transmission Licensee or the User(s) become aware that a
change is needed to a Local Switching Procedure, they must inform NGET
immediately. Where NGET has been informed of a need for a change, or NGET
proposes a change, NGET shall notify both the affected User and the Relevant
Transmission Licensee and will initiate discussions to agree a change to the
Local Switching Procedure. The principles applying to the establishment of a new
Local Switching Procedure shall then apply to the discussion and agreement of
any changes.
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OC7.4.8.8
NATIONAL ELECTRICITY
TRANSMISSION
SYSTEM WARNING –
Risk of System
Disturbance
OC7.4.8.6
NATIONAL ELECTRICITY
TRANSMISSION
SYSTEM WARNING –
High risk of Demand
Reduction
OC7.4.8.7
OC7.4.8.5
NATIONAL ELECTRICITY
TRANSMISSION
WARNING –
ELECTRICITY MARGIN
NOTICE
NATIONAL ELECTRICITY
TRANSMISSION
SYSTEM WARNING –
Demand Control
Imminent
GRID
CODE
WARNING TYPE
Fax/Teleph
one or
other
electronic
means
Fax/Teleph
one or
other
electronic
means
Fax or
other
electronic
means
Fax or
other
electronic
means
FORMAT
Generators, DC Converter
Station owners
Network Operators, NonEmbedded Customers,
Externally Interconnected
System Operators who
may be affected.
Specified Users only: (to
whom an instruction is to
be given)
Network Operators, NonEmbedded Customers
Generators,
Suppliers,
Network Operators,
Non-Embedded
Customers,
Externally Interconnected
System Operators, DC
Converter Station Owners
Generators,
Suppliers,
Externally Interconected
System Operators, DC
Converter Station owners
TO: FOR ACTION
Suppliers
None
Network
Operators, NonEmbedded
Customers
TO: FOR
INFORMATION
Control room time
scales
Within 30 minutes of
anticipated
instruction
Primarily 1200 hours
onwards for a future
period
All timescales where
there is a high risk of
Demand Reduction.
Notification that if not
improved Demand
reduction may be
instructed.
Primarily 1200 hours
onwards for a future
period.
Risk of, widespread system
disturbance to whole or part
of the National Electricity
Transmission System
Possibility of Demand
Reduction within 30
minutes
(May be issued locally as
demand reduction risk only
for circuit overloads)
Insufficient generation
available to meet forecast
Demand plus Operating
Margin and/or a high risk of
Demand Reduction being
instructed.
(Normal initial warning of
insufficient System Margin
Insufficient generation
available to meet forecast
Demand plus Operating
Margin.
WARNING OF/OR
CONSEQUENCE
All timescales when
at the time there is
not a high risk of
Demand reduction.
TIMESCALE
Recipients take steps to warn
operational staff and maintain plant or
apparatus such that they are best
able to withstand the disturbance.
Network Operators specified to
prepare to take action as necessary
to enable them to comply with any
subsequent NGET instruction for
Demand reduction.
(Percentages of Demand Reduction
above 20% may not be achieved if
NGET has not issued the warning by
16:00 hours the previous day.)
Specified Network Operators and
Non-Embedded Customers to
prepare their Demand Reduction
arrangements and take actions as
necessary to enable compliance with
NGET instructions that may follow.
Suppliers notify NGET of any
additional Customer Demand
Management that they will initiate.
Offers of increased availability from
Generators or DC Converter Station
owners and Interconnector Users.
Suppliers notify NGET of any
additional Customer Demand
Management that they will initiate.
Offers of increased availability from
Generators or DC Converter Station
owners and Interconnector Users.
RESPONSE FROM RECIPIENTS
APPENDIX 1 - NATIONAL ELECTRICITY TRANSMISSION SYSTEM
WARNINGS TABLE
< END OF OPERATING CODE NO. 7 >
30 September 2016
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OPERATING CODE NO. 8
(OC8)
SAFETY CO-ORDINATION
CONTENTS
(This contents page does not form part of the Grid Code)
Page Number
Paragraph No/Title
OC8.1 INTRODUCTION.................................................................................................................................. 2
OC8.2 OBJECTIVE ......................................................................................................................................... 2
OC8.3 SCOPE................................................................................................................................................. 2
OC8.4 PROCEDURE ...................................................................................................................................... 2
OC8.4.1 Safety Co-Ordination In Respect Of The E&W Transmission Systems Or The Systems
Of E&W Users............................................................................................................................................ 2
OC8.4.2
Safety Co-Ordination In Respect Of The Scottish Transmission Systems Or The
Systems Of Scottish Users ........................................................................................................................ 3
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OC8.1
INTRODUCTION
OC8.1.1
OC8 specifies the standard procedures to be used for the co-ordination, establishment and
maintenance of necessary Safety Precautions when work is to be carried out on or near the
National Electricity Transmission System or the System of a User and when there is a
need for Safety Precautions on HV Apparatus on the other System for this work to be
carried out safely. OC8 Appendix 1 applies when work is to be carried out on or near to E&W
Transmission Systems or the Systems of E&W Users and OC8 Appendix 2 applies when
work is to be carried out on or near to Scottish Transmission Systems or the Systems of
Scottish Users.
OC8.1.2
OC8 also covers the co-ordination, establishment and maintenance of necessary safety
precautions on the Implementing Safety Co-ordinator’s System when work is to be
carried out at a User’s Site or a Transmission Site (as the case may be) on equipment of
the User or a Transmission Licensee as the case may be where the work or equipment is
near to HV Apparatus on the Implementing Safety Co-ordinator’s System.
OC8.2
OBJECTIVE
OC8.2.1
The objective of OC8 is to achieve:
(i)
Safety From The System when work on or near a System necessitates the provision
of Safety Precautions on another System on HV Apparatus up to a Connection
Point; and
(ii)
Safety From The System when work is to be carried out at a User’s Site or a
Transmission Site (as the case may be) on equipment of the User or a Transmission
Licensee (as the case may be) where the work or equipment is near to HV Apparatus
on the Implementing Safety Co-ordinator’s System.
OC8.3
SCOPE
OC8.3.1
OC8 applies to NGET and to Users, which in OC8 means:
(a) Generators (including where undertaking OTSDUW);
(b) Network Operators; and
(c) Non-Embedded Customers.
In Scotland and Offshore OC8 also applies to Relevant Transmission Licensees.
The procedures for the establishment of safety co-ordination by NGET in relation to External
Interconnections are set out in Interconnection Agreements with relevant persons for the
External Interconnections.
OC8.4
PROCEDURE
OC8.4.1
Safety Co-Ordination In Respect Of The E&W Transmission Systems Or The Systems Of
E&W Users
OC8.4.1.1
OC8 Appendix 1, OC8A, applies when work is to be carried out on or near to the E&W
Transmission System or the Systems of E&W Users or when Safety Precautions are
required to be established on the E&W Transmission System or the Systems of E&W
Users when work is to be carried out on or near to the Scottish Transmission System or
the Systems of Scottish Users.
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OC8.4.2
Safety Co-Ordination In Respect Of The Scottish Transmission Systems Or The Systems Of
Scottish Users
OC8.4.2.1
OC8 Appendix 2, OC8B, applies when work is to be carried out on or near to the Scottish
Transmission System or the Systems of Scottish Users or when Safety Precautions are
required to be established on the Scottish Transmission System or the Systems of
Scottish Users when work is to be carried out on or near to the E&W Transmission
System or the Systems of E&W Users.
OC8.4.3
Safety Co-ordination Offshore
OC8.4.3.1
For the purposes of OC8 Appendix 1, OC8A, OC8 Appendix 2 and OC8B, when work is to
be carried out on or near to Offshore Transmission Systems Safety Precautions shall be
established by the Offshore Transmission Licensee and the Offshore User.
< END OF OPERATING CODE NO. 8 >
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OPERATING CODE NO. 8 APPENDIX 1
(OC8A)
SAFETY CO-ORDINATION IN RESPECT OF THE E&W TRANSMISSION SYSTEMS OR
THE SYSTEMS OF E&W USERS
CONTENTS
(This contents page does not form part of the Grid Code)
Page Number
Paragraph No/Title
OC8A.1 INTRODUCTION ............................................................................................................................... 2
OC8A.2 OBJECTIVE....................................................................................................................................... 3
OC8A.3 SCOPE .............................................................................................................................................. 4
OC8A.4 PROCEDURE.................................................................................................................................... 4
OC8A.4.1 Approval Of Local Safety Instructions..................................................................................... 4
OC8A.4.2 Safety Co-ordinators ............................................................................................................... 5
OC8A.4.3 RISSP ..................................................................................................................................... 5
OC8A.5 SAFETY PRECAUTIONS ON HV APPARATUS .............................................................................. 6
OC8A.5.1 Agreement Of Safety Precautions .......................................................................................... 6
OC8A.5.2 Implementation Of Isolation .................................................................................................... 6
OC8A.5.3 Implementation Of Earthing .................................................................................................... 7
OC8A.5.4 RISSP Issue Procedure .......................................................................................................... 8
OC8A.5.5 RISSP Cancellation Procedure............................................................................................. 10
OC8A.5.6 RISSP Change Control ......................................................................................................... 10
OC8A.6 TESTING AFFECTING ANOTHER SAFETY CO-ORDINATOR’S SYSTEM ................................. 10
OC8A.7 EMERGENCY SITUATIONS........................................................................................................... 11
OC8A.8 SAFETY PRECAUTIONS RELATING TO WORKING ON EQUIPMENT NEAR TO THE HV
SYSTEM .......................................................................................................................................................... 12
OC8A.8.1 Agreement of Safety Precautions ......................................................................................... 12
OC8A.8.2 Implementation of Isolation and Earthing ............................................................................. 12
OC8A.8.3 Permit For Work For Proximity Work Issue Procedure......................................................... 13
OC8A.8.4 Permit For Work For Proximity Work Cancellation Procedure ............................................. 13
OC8A.9 LOSS OF INTEGRITY OF SAFETY PRECAUTIONS..................................................................... 13
OC8A.10 SAFETY LOG ................................................................................................................................ 13
APPENDIX A - RISSP-R ................................................................................................................................. 14
APPENDIX B - RISSP-I................................................................................................................................... 16
APPENDIX C- FLOWCHARTS ....................................................................................................................... 18
APPENDIX C1 - RISSP ISSUE PROCESS ............................................................................................ 18
APPENDIX C2 - TESTING PROCESS ................................................................................................... 19
APPENDIX C3 - RISSP CANCELLATION PROCESS............................................................................ 20
APPENDIX C4 - PROCESS FOR WORKING NEAR TO SYSTEM EQUIPMENT ................................. 21
APPENDIX D - NATIONAL GRID SAFETY CIRCULAR................................................................................. 22
APPENDIX E - FORM OF NGET PERMIT TO WORK ................................................................................... 23
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OC8A.1
INTRODUCTION
OC8A.1.1
OC8A specifies the standard procedures to be used by the Relevant E&W Transmission
Licensee, NGET (where NGET is not the Relevant E&W Transmission Licensee) and
Users for the co-ordination, establishment and maintenance of necessary Safety
Precautions when work is to be carried out on or near the E&W Transmission System or
the System of an E&W User and when there is a need for Safety Precautions on HV
Apparatus on the other's System for this work to be carried out safely. OC8A applies to
Relevant E&W Transmission Licensees and E&W Users only. Where work is to be
carried out on or near equipment on the Scottish Transmission System or Systems of
Scottish Users, but such work requires Safety Precautions to be established on the E&W
Transmission System or the Systems of E&W Users, OC8A should be followed by the
Relevant E&W Transmission Licensee and E&W Users to establish the required Safety
Precautions.
OC8B specifies the procedures to be used by the Relevant Scottish Transmission
Licensees and Scottish Users.
In this OC8A the term “work” includes testing, other than System Tests which are covered
by OC12.
OC8A.1.2
OC8A also covers the co-ordination, establishment and maintenance of necessary safety
precautions on the Implementing Safety Co-ordinator’s System when work is to be
carried out at an E&W User’s Site or a Transmission Site (as the case may be) on
equipment of the E&W User or the Relevant E&W Transmission Licensee as the case
may be where the work or equipment is near to HV Apparatus on the Implementing Safety
Co-ordinator’s System. In the case of OTSUA, an E&W User’s Site or Transmission
Site shall, for the purposes of this OC8A, include a site at which there is a Transmission
Interface Point until the OTSUA Transfer Time and the provisions of this OC8A and
references to OTSUA shall be construed and applied accordingly until the OTSUA Transfer
Time at which time arrangements in respect of the Transmission Interface Site will have
been put in place between the Relevant E&W Transmission Licensee and the Offshore
Transmission Licensee.
OC8A.1.3
OC8A does not apply to the situation where Safety Precautions need to be agreed solely
between E&W Users. OC8A does not apply to the situation where Safety Precautions
need to be agreed solely between Transmission Licensees.
OC8A.1.4
OC8A does not seek to impose a particular set of Safety Rules on the Relevant E&W
Transmission Licensee and E&W Users; the Safety Rules to be adopted and used by the
Relevant E&W Transmission Licensee and each E&W User shall be those chosen by
each.
OC8A.1.5
Site Responsibility Schedules document the control responsibility for each item of Plant
and Apparatus for each site.
OC8A.1.6
Defined Terms
OC8A.1.6.1
E&W Users should bear in mind that in OC8 only, in order that OC8 reads more easily with
the terminology used in certain Safety Rules, the term "HV Apparatus" is defined more
restrictively and is used accordingly in OC8A. E&W Users should, therefore, exercise
caution in relation to this term when reading and using OC8A.
OC8A.1.6.2
In OC8A only the following terms shall have the following meanings:
(1) "HV Apparatus" means High Voltage electrical circuits forming part of a System, on
which Safety From The System may be required or on which Safety Precautions may
be applied to allow work to be carried out on a System.
(2) "Isolation" means the disconnection of Apparatus from the remainder of the System in
which that Apparatus is situated by either of the following:
(a) an Isolating Device maintained in an isolating position. The isolating position must
either be:
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(i)
maintained by immobilising and Locking the Isolating Device in the isolating
position and affixing a Caution Notice to it. Where the Isolating Device is
Locked with a Safety Key, the Safety Key must be secured in a Key Safe
and the Key Safe Key must be, where reasonably practicable, given to the
authorised site representative of the Requesting Safety Co-ordinator and is
to be retained in safe custody. Where not reasonably practicable the Key
Safe Key must be retained by the authorised site representative of the
Implementing Safety Co-ordinator in safe custody; or
(ii)
maintained and/or secured by such other method which must be in
accordance with the Local Safety Instructions of the Relevant E&W
Transmission Licensee or that E&W User, as the case may be; or
(b) an adequate physical separation which must be in accordance with, and
maintained by, the method set out in the Local Safety Instructions of the
Relevant E&W Transmission Licensee or that E&W User, as the case may be,
and, if it is a part of that method, a Caution Notice must be placed at the point of
separation;
or
(c) in the case where the relevant HV Apparatus of the Implementing Safety Coordinator is being either constructed or modified, an adequate physical separation
as a result of a No System Connection.
(3) “No System Connection” means an adequate physical separation (which must be in
accordance with, and maintained by, the method set out in the Local Safety
Instructions of the Implementing Safety Co-ordinator) of the Implementing Safety
Co-ordinator’s HV Apparatus from the rest of the Implementing Safety Coordinator’s System where such HV Apparatus has no installed means of being
connected to, and will not for the duration of the Safety Precaution be connected to, a
source of electrical energy or to any other part of the Implementing Safety Coordinators System.
(4) "Earthing" means a way of providing a connection between conductors and earth by an
Earthing Device which is either:
(i)
immobilised and Locked in the earthing position. Where the Earthing Device is
Locked with a Safety Key, the Safety Key must be secured in a Key Safe and the
Key Safe Key must be, where reasonably practicable, given to the authorised site
representative of the Requesting Safety Co-ordinator and is to be retained in safe
custody. Where not reasonably practicable the Key Safe Key must be retained by
the authorised site representative of the Implementing Safety Co-ordinator in safe
custody; or
(ii)
maintained and/or secured in position by such other method which must be in
accordance with the Local Safety Instructions of the Relevant E&W
Transmission Licensee or that E&W User as the case may be.
OC8A.1.6.3
For the purpose of the co-ordination of safety relating to HV Apparatus the term “Safety
Precautions” means Isolation and/or Earthing.
OC8A.2
OBJECTIVE
OC8A.2.1
The objective of OC8A is to achieve:-
Issue 5 Revision 8
(i)
Safety From The System when work on or near a System necessitates the provision
of Safety Precautions on another System on HV Apparatus up to a Connection
Point (or, in the case of OTSUA, Transmission Interface Point); and
(ii)
Safety From The System when work is to be carried out at an E&W User’s Site or a
Transmission Site (as the case may be) on equipment of the User or the Relevant
E&W Transmission Licensee (as the case may be) where the work or equipment is
near to HV Apparatus on the Implementing Safety Co-ordinator’s System.
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OC8A.2.2
A flow chart, set out in OC8A Appendix C, illustrates the process utilised in OC8A to
achieve the objective set out in OC8A.2.1. In the case of a conflict between the flow chart
and the provisions of the written text of OC8A, the written text will prevail.
OC8A.3
SCOPE
OC8A.3.1
OC8A applies to the Relevant E&W Transmission Licensee and to E&W Users, which in
OC8A means:
(a) Generators (including where undertaking OTSDUW);
(b) Network Operators; and
(c) Non-Embedded Customers.
The procedures for the establishment of safety co-ordination by the Relevant E&W
Transmission Licensee in relation to External Interconnections are set out in
Interconnection Agreements with relevant persons for the External Interconnections.
OC8A.4
PROCEDURE
OC8A.4.1
Approval Of Local Safety Instructions
OC8A.4.1.1
(a) In accordance with the timing requirements of its Bilateral Agreement, each E&W
User will supply to the Relevant E&W Transmission Licensee a copy of its Local
Safety Instructions relating to its side of the Connection Point at each Connection
Site, or in the case of OTSUA a copy of its Local Safety Instructions relating to its
side of the Transmission Interface Point at each Transmission Interface Site.
(b) In accordance with the timing requirements of each Bilateral Agreement, the Relevant
E&W Transmission Licensee will supply to each E&W User a copy of its Local Safety
Instructions relating to the Transmission side of the Connection Point at each
Connection Site, or in the case of OTSUA a copy of its Local Safety Instructions
relating to the Transmission side of the Transmission Interface Point at each
Transmission Interface Site.
(c) Prior to connection the Relevant E&W Transmission Licensee and the E&W User
must have approved each other's relevant Local Safety Instructions in relation to
Isolation and Earthing.
OC8A.4.1.2
Either party may require that the Isolation and/or Earthing provisions in the other party’s
Local Safety Instructions affecting the Connection Site (or, in the case of OTSUA,
Transmission Interface Site) should be made more stringent in order that approval of the
other party’s Local Safety Instructions can be given. Provided these requirements are not
unreasonable, the other party will make such changes as soon as reasonably practicable.
These changes may need to cover the application of Isolation and/or Earthing at a place
remote from the Connection Site (or, in the case of OTSUA, Transmission Interface Site),
depending upon the System layout. Approval may not be withheld because the party
required to approve reasonably believes the provisions relating to Isolation and/or Earthing
are too stringent.
OC8A.4.1.3
If, following approval, a party wishes to change the provisions in its Local Safety
Instructions relating to Isolation and/or Earthing, it must inform the other party. If the
change is to make the provisions more stringent, then the other party merely has to note the
changes. If the change is to make the provisions less stringent, then the other party needs to
approve the new provisions and the procedures referred to in OC8A.4.1.2 apply.
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OC8A.4.2
Safety Co-ordinators
OC8A.4.2.1
For each Connection Point, (or, in the case of OTSUA, Transmission Interface Point),
the Relevant E&W Transmission Licensee and each E&W User will at all times have
nominated and available a person or persons (“Safety Co-ordinator(s)”) to be responsible
for the co-ordination of Safety Precautions when work is to be carried out on a System
which necessitates the provision of Safety Precautions on HV Apparatus pursuant to
OC8A. A Safety Co-ordinator may be responsible for the co-ordination of safety on HV
Apparatus at more than one Connection Point (or, in the case of OTSUA, Transmission
Interface Point).
OC8A.4.2.2
Each Safety Co-ordinator shall be authorised by the Relevant E&W Transmission
Licensee or an E&W User, as the case may be, as competent to carry out the functions set
out in OC8A to achieve Safety From The System. Confirmation from the Relevant E&W
Transmission Licensee or an E&W User, as the case may be, that its Safety Coordinator(s) as a group are so authorised is dealt with in CC.5.2. Only persons with such
authorisation will carry out the provisions of OC8A.
OC8A.4.2.3
Contact between Safety Co-ordinators will be made via normal operational channels, and
accordingly separate telephone numbers for Safety Co-ordinators need not be provided. At
the time of making contact, each party will confirm that they are authorised to act as a Safety
Co-ordinator, pursuant to OC8A.
OC8A.4.2.4
If work is to be carried out on a System, or on equipment of the Relevant E&W
Transmission Licensee or an E&W User near to a System, as provided in this OC8A,
which necessitates the provision of Safety Precautions on HV Apparatus in accordance
with the provisions of OC8A, the Requesting Safety Co-ordinator who requires the Safety
Precautions to be provided shall contact the relevant Implementing Safety Co-ordinator
to co-ordinate the establishment of the Safety Precautions.
OC8A.4.3
RISSP
OC8A.4.3.1
OC8A sets out the procedures for utilising the RISSP, which will be used except where
dealing with equipment in proximity to the other’s System as provided in OC8A.8. Sections
OC8A.4 to OC8A.7 inclusive should be read accordingly.
OC8A.4.3.2
The Relevant E&W Transmission Licensee will use the format of the RISSP forms set out
in Appendix A and Appendix B to OC8A. That set out in OC8A Appendix A and designated
as "RISSP-R", shall be used when the Relevant E&W Transmission Licensee is the
Requesting Safety Co-ordinator, and that in OC8A Appendix B and designated as
"RISSP-I", shall be used when the Relevant E&W Transmission Licensee is the
Implementing Safety Co-ordinator. Proformas of RISSP-R and RISSP-I will be provided
for use by the Relevant E&W Transmission Licensee staff.
OC8A.4.3.3
(a)
E&W Users may either adopt the format referred to in OC8A.4.3.2, or use an equivalent
format, provided that it includes sections requiring insertion of the same information and
has the same numbering of sections as RISSP-R and RISSP-I as set out in Appendices
A and B respectively.
(b) Whether E&W Users adopt the format referred to in OC8A.4.3.2, or use the equivalent
format as above, the format may be produced and held in, and retrieved from an
electronic form by the E&W User.
(c) Whichever method E&W Users choose, each must provide proformas (whether in
tangible or electronic form) for use by its staff.
OC8A.4.3.4
All references to RISSP-R and RISSP-I shall be taken as referring to the corresponding parts
of the alternative forms or other tangible written or electronic records used by each E&W
User.
OC8A.4.3.5
RISSP-R will have an identifying number written or printed on it, comprising a prefix which
identifies the location at which it is issued, and a unique (for each E&W User or the
Relevant E&W Transmission Licensee, as the case may be) serial number which both
together uses up to eight characters (including letters and numbers) and the suffix "R".
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OC8A.4.3.6
(a) In accordance with the timing requirements set out in CC.5.2 each E&W User shall
apply in writing to the Relevant E&W Transmission Licensee for the Relevant E&W
Transmission Licensee’s approval of its proposed prefix.
(b) The Relevant E&W Transmission Licensee shall consider the proposed prefix to see
if it is the same as (or confusingly similar to) a prefix used by the Relevant E&W
Transmission Licensee or another User and shall, as soon as possible (and in any
event within ten days), respond in writing to the E&W User with its approval or
disapproval.
(c) If the Relevant E&W Transmission Licensee disapproves, it shall explain in its
response why it has disapproved and will suggest an alternative prefix.
(d) If the Relevant E&W Transmission Licensee has disapproved, then the E&W User
shall either notify the Relevant E&W Transmission Licensee in writing of its
acceptance of the suggested alternative prefix or it shall apply in writing to the Relevant
E&W Transmission Licensee with revised proposals and the above procedure shall
apply to that application.
OC8A.4.3.7
The prefix allocation will be periodically circulated by NGET to all E&W Users, for
information purposes, using a National Grid Safety Circular in the form set out in OC8A
Appendix D.
OC8A.5
SAFETY PRECAUTIONS ON HV APPARATUS
OC8A.5.1
Agreement Of Safety Precautions
OC8A.5.1.1
The Requesting Safety Co-ordinator who requires Safety Precautions on another
System(s) will contact the relevant Implementing Safety Co-ordinator(s) to agree the
Location of the Safety Precautions to be established. This agreement will be recorded in
the respective Safety Logs.
OC8A.5.1.2
It is the responsibility of the Implementing Safety Co-ordinator to ensure that adequate
Safety Precautions are established and maintained, on his and/or another System
connected to his System, to enable Safety From The System to be achieved on the HV
Apparatus, specified by the Requesting Safety Co-ordinator which is to be identified in
Part 1.1 of the RISSP. Reference to another System in this OC8A.5.1.2 shall not include
the Requesting Safety Co-ordinator’s System which is dealt with in OC8A.5.1.3.
OC8A.5.1.3
When the Implementing Safety Co-ordinator is of the reasonable opinion that it is
necessary for Safety Precautions on the System of the Requesting Safety Co-ordinator,
other than on the HV Apparatus specified by the Requesting Safety Co-ordinator, which
is to be identified in Part 1.1 of the RISSP, he shall contact the Requesting Safety Coordinator and the details shall be recorded in part 1.1 of the RISSP forms. In these
circumstances it is the responsibility of the Requesting Safety Co-ordinator to establish
and maintain such Safety Precautions.
OC8A.5.1.4
In The Event Of Disagreement
In any case where the Requesting Safety Co-ordinator and the Implementing Safety Coordinator are unable to agree the Location of the Isolation and (if requested) Earthing,
both shall be at the closest available points on the infeeds to the HV Apparatus on which
Safety From The System is to be achieved as indicated on the Operation Diagram.
OC8A.5.2
Implementation Of Isolation
OC8A.5.2.1
Following the agreement of the Safety Precautions in accordance with OC8A.5.1 the
Implementing Safety Co-ordinator shall then establish the agreed Isolation.
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OC8A.5.2.2
The Implementing Safety Co-ordinator shall confirm to the Requesting Safety Coordinator that the agreed Isolation has been established, and identify the Requesting
Safety Co-ordinator's HV Apparatus up to the Connection Point (or, in the case of
OTSUA, Transmission Interface Point), for which the Isolation has been provided. The
confirmation shall specify:
(a) for each Location, the identity (by means of HV Apparatus name, nomenclature and
numbering or position, as applicable) of each point of Isolation;
(b) whether Isolation has been achieved by an Isolating Device in the isolating position,
by an adequate physical separation or as a result of a No System Connection;
(c) where an Isolating Device has been used whether the isolating position is either:
(i)
maintained by immobilising and Locking the Isolating Device in the isolating
position and affixing a Caution Notice to it. Where the Isolating Device has been
Locked with a Safety Key, the confirmation shall specify that the Safety Key has
been secured in a Key Safe and the Key Safe Key has been given to the
authorised site representative of the Requesting Safety Co-ordinator where
reasonably practicable and is to be retained in safe custody. Where not
reasonably practicable (including where Earthing has been requested in
OC8A.5.1), the confirmation shall specify that the Key Safe Key will be retained by
the authorised site representative of the Implementing Safety Co-ordinator in
safe custody; or
(ii)
maintained and/or secured by such other method which must be in accordance
with the Local Safety Instructions of the Relevant E&W Transmission Licensee
or that E&W User, as the case may be; and
(d) where an adequate physical separation has been used that it will be in accordance with,
and maintained by, the method set out in the Local Safety Instructions of the
Relevant E&W Transmission Licensee or that E&W User, as the case may be, and, if
it is a part of that method, that a Caution Notice has been placed at the point of
separation;
(e) where a No System Connection has been used the physical position of the No
System Connection shall be defined and shall not be varied for the duration of Safety
Precaution and the Implementing Safety Co-ordinator’s relevant HV Apparatus will
not, for the duration of the Safety Precaution be connected to a source of electrical
energy or to any other part of the Implementing Safety Co-ordinator’s System.
The confirmation of Isolation shall be recorded in the respective Safety Logs.
OC8A.5.2.3
Following the confirmation of Isolation being established by the Implementing Safety Coordinator and the necessary establishment of relevant Isolation on the Requesting Safety
Co-ordinators System, the Requesting Safety Co-ordinator will then request the
implementation of Earthing by the Implementing Safety Co-ordinator, if agreed in section
OC8A.5.1. If the implementation of Earthing has been agreed, then the authorised site
representative of the Implementing Safety Co-ordinator shall retain any Key Safe Key in
safe custody until any Safety Key used for Earthing has been secured in the Key Safe.
OC8A.5.3
Implementation Of Earthing
OC8A.5.3.1
The Implementing Safety Co-ordinator shall then establish the agreed Earthing.
OC8A.5.3.2
The Implementing Safety Co-ordinator shall confirm to the Requesting Safety Coordinator that the agreed Earthing has been established, and identify the Requesting
Safety Co-ordinator’s HV Apparatus up to the Connection Point (or, in the case of
OTSUA, Transmission Interface Point), for which the Earthing has been provided. The
confirmation shall specify:
(a) for each Location, the identity (by means of HV Apparatus name, nomenclature and
numbering or position, as is applicable) of each point of Earthing; and
(b) in respect of the Earthing Device used, whether it is:
(i)
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been Locked with a Safety Key, that the Safety Key has been secured in a Key
Safe and the Key Safe Key has been given to the authorised site representative of
the Requesting Safety Co-ordinator where reasonably practicable and is to be
retained in safe custody. Where not reasonably practicable, that the Key Safe Key
will be retained by the authorised site representative of the Implementing Safety
Co-ordinator in safe custody; or
(ii)
maintained and/or secured in position by such other method which is in
accordance with the Local Safety Instructions of the Relevant E&W
Transmission Licensee or the Relevant Transmission Licensee or that E&W
User, as the case may be.
The confirmation of Earthing shall be recorded in the respective Safety Logs.
OC8A.5.3.3.
The Implementing Safety Co-ordinator shall ensure that the established Safety
Precautions are maintained until requested to be removed by the relevant Requesting
Safety Co-ordinator.
OC8A.5.3.4
Certain designs of gas insulated switchgear three position isolator and earth switches
specifically provide a combined Isolation and Earthing function within a single mechanism
contained within a single integral unit. Where Safety Precautions are required across
control boundaries and subject to the requirements of OC8A.5.1, it is permissible to earth
before Points of Isolation have been established provided that all interconnected circuits
are fully disconnected from live HV Apparatus.
OC8A.5.4
RISSP Issue Procedure
OC8A.5.4.1
Where Safety Precautions on another System(s) are being provided to enable work on the
Requesting Safety Co-ordinator’s System, before any work commences they must be
recorded by a RISSP being issued. The RISSP is applicable to HV Apparatus up to the
Connection Point (or, in the case of OTSUA, Transmission Interface Point) identified in
section 1.1 of the RISSP-R and RISSP-I forms.
OC8A.5.4.2
Where Safety Precautions are being provided to enable work to be carried out on both
sides of the Connection Point (or, in the case of OTSUA, Transmission Interface Point) a
RISSP will need to be issued for each side of the Connection Point (or, in the case of
OTSUA, Transmission Interface Point) with the Relevant E&W Transmission Licensee
and the respective User each enacting the role of Requesting Safety Co-ordinator. This
will result in a RISSP-R and a RISSP-I form being completed by each of the Relevant E&W
Transmission Licensee and the E&W User, with each Requesting Safety Co-ordinator
issuing a separate RISSP number.
OC8A.5.4.3
Once the Safety Precautions have been established (in accordance with OC8A.5.2 and
OC8A.5.3), the Implementing Safety Co-ordinator shall complete parts 1.1 and 1.2 of a
RISSP-I form recording the details specified in OC8A.5.1.3, OC8A.5.2.2 and OC8A.5.3.2.
Where Earthing has not been requested, Part 1.2(b) will be completed with the words “not
applicable” or “N/A”. He shall then contact the Requesting Safety Co-ordinator to pass on
these details.
OC8A.5.4.4
The Requesting Safety Co-ordinator shall complete Parts 1.1 and 1.2 of the RISSP-R,
making a precise copy of the details received. On completion, the Requesting Safety Coordinator shall read the entries made back to the sender and check that an accurate copy
has been made.
OC8A.5.4.5
The Requesting Safety Co-ordinator shall then issue the number of the RISSP, taken from
the RISSP-R, to the Implementing Safety Co-ordinator who will ensure that the number,
including the prefix and suffix, is accurately recorded in the designated space on the RISSP-I
form.
OC8A.5.4.6
The Requesting Safety Co-ordinator and the Implementing Safety Co-ordinator shall
complete and sign Part 1.3 of the RISSP-R and RISSP-I respectively and then enter the time
and date. When signed no alteration to the RISSP is permitted; the RISSP may only be
cancelled.
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OC8A.5.4.7
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The Requesting Safety Co-ordinator is then free to authorise work (including a test that
does not affect the Implementing Safety Co-ordinator's System) in accordance with the
requirements of the relevant internal safety procedures which apply to the Requesting
Safety Co-ordinator’s System. This is likely to involve the issue of safety documents or
other relevant internal authorisations. Where testing is to be carried out which affects the
Implementing Safety Co-ordinator's System, the procedure set out below in OC8A.6 shall
be implemented.
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OC8A.5.5
RISSP Cancellation Procedure
OC8A.5.5.1
When the Requesting Safety Co-ordinator decides that Safety Precautions are no longer
required, he will contact the relevant Implementing Safety Co-ordinator to effect
cancellation of the associated RISSP.
OC8A.5.5.2
The Requesting Safety Co-ordinator will inform the relevant Implementing Safety Coordinator of the RISSP identifying number (including the prefix and suffix), and agree it is
the RISSP to be cancelled.
OC8A.5.5.3
The Requesting Safety Co-ordinator and the relevant Implementing Safety Co-ordinator
shall then respectively complete Part 2.1 of their respective RISSP-R and RISSP-I forms and
shall then exchange details. The details being exchanged shall include their respective
names and time and date. On completion of the exchange of details the respective RISSP is
cancelled. The removal of Safety Precautions is as set out in OC8A.5.5.4 and OC8A.5.5.5.
OC8A.5.5.4
Neither Safety Co-ordinator shall instruct the removal of any Isolation forming part of the
Safety Precautions as part of the returning of the HV Apparatus to service until it is
confirmed to each by each other that every earth on each side of the Connection Point (or,
in the case of OTSUA, Transmission Interface Point), within the points of isolation
identified on the RISSP, has been removed or disconnected by the provision of additional
Points of Isolation.
OC8A.5.5.5
Subject to the provisions in OC8A.5.5.4, the Implementing Safety Co-ordinator is then free
to arrange the removal of the Safety Precautions, the procedure to achieve that being
entirely an internal matter for the party the Implementing Safety Co-ordinator is
representing. Where a Key Safe Key has been given to the authorised site representative of
the Requesting Safety Co-ordinator, the Key Safe Key must be returned to the authorised
site representative of the Implementing Safety Co-ordinator. The only situation in which
any Safety Precautions may be removed without first cancelling the RISSP in accordance
with OC8A.5.5 or OC8A.5.6 is when Earthing is removed in the situation envisaged in
OC8A.6.2(b).
OC8A.5.6
RISSP Change Control
Nothing in this OC8A prevents the Relevant E&W Transmission Licensee and E&W
Users agreeing to a simultaneous cancellation and issue of a new RISSP, if both agree. It
should be noted, however, that the effect of that under the relevant Safety Rules is not a
matter with which the Grid Code deals.
OC8A.6
TESTING AFFECTING ANOTHER SAFETY CO-ORDINATOR'S SYSTEM
OC8A.6.1
The carrying out of the test may affect Safety Precautions on RISSPs or work being carried
out which does not require a RISSP. Testing can, for example, include the application of an
independent test voltage. Accordingly, where the Requesting Safety Co-ordinator wishes
to authorise the carrying out of such a test to which the procedures in OC8A.6 apply he may
not do so and the test will not take place unless and until the steps in (a)-(c) below have
been followed and confirmation of completion has been recorded in the respective Safety
Logs:
(a) confirmation must be obtained from the Implementing Safety Co-ordinator that:
(i)
no person is working on, or testing, or has been authorised to work on, or test, any
part of its System or another System(s) (other than the System of the
Requesting Safety Co-ordinator) within the points of Isolation identified on the
RISSP form relating to the test which is proposed to be undertaken, and
(ii)
no person will be so authorised until the proposed test has been completed (or
cancelled) and the Requesting Safety Co-ordinator has notified the
Implementing Safety Co-ordinator of its completion (or cancellation);
(b) any other current RISSPs which relate to the parts of the System in which the testing is
to take place must have been cancelled in accordance with procedures set out in
OC8A.5.5;
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(c) the Implementing Safety Co-ordinator must agree with the Requesting Safety Coordinator to permit the testing on that part of the System between the points of
Isolation identified in the RISSP associated with the test and the points of Isolation on
the Requesting Safety Co-ordinator's System.
OC8A.6.2
(a) The Requesting Safety Co-ordinator will inform the Implementing Safety Coordinator as soon as the test has been completed or cancelled and the confirmation
shall be recorded in the respective Safety Logs.
(b) When the test gives rise to the removal of Earthing which it is not intended to re-apply,
the relevant RISSP associated with the test shall be cancelled at the completion or
cancellation of the test in accordance with the procedure set out in either OC8A.5.5 or
OC8A.5.6. Where the Earthing is re-applied following the completion or cancellation of
the test, there is no requirement to cancel the relevant RISSP associated with the test
pursuant to this OC8A.6.2.
OC8A.7
EMERGENCY SITUATIONS
OC8A.7.1
There may be circumstances where Safety Precautions need to be established in relation
to an unintended electrical connection or situations where there is an unintended risk of
electrical connection between the National Electricity Transmission System and an E&W
User’s System, for example resulting from an incident where one line becomes attached or
unacceptably close to another.
OC8A.7.2
In those circumstances, if both the Relevant E&W Transmission Licensee and the
respective E&W User agree, the relevant provisions of OC8A.5 will apply as if the electrical
connections or potential connections were, solely for the purposes of this OC8A, a
Connection Point (or, in the case of OTSUA, Transmission Interface Point).
OC8A.7.3
(a) The relevant Safety Co-ordinator shall be that for the electrically closest existing
Connection Point (or, in the case of OTSUA, Transmission Interface Point) to that
E&W User's System or such other local Connection Point (or, in the case of OTSUA,
Transmission Interface Point) as may be agreed between the Relevant E&W
Transmission Licensee and the E&W User, with discussions taking place between the
relevant local Safety Co-ordinators. The Connection Point (or, in the case of OTSUA,
Transmission Interface Point) to be used shall be known in this OC8A.7.3 as the
"relevant Connection Point" (or, in the case of OTSUA, “relevant Transmission
Interface Point”).
(b) The Local Safety Instructions shall be those which apply to the relevant Connection
Point (or, in the case of OTSUA, Transmission Interface Point).
(c) The prefix for the RISSP will be that which applies for the relevant Connection Point
(or, in the case of OTSUA, Transmission Interface Point).
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OC8A.8
SAFETY PRECAUTIONS RELATING TO WORKING ON EQUIPMENT NEAR TO THE HV
SYSTEM
OC8A.8 applies to the situation where work is to be carried out at an E&W User’s Site or a
Transmission Site (as the case may be) on equipment of the User or the Relevant E&W
Transmission Licensee as the case may be, where the work or equipment is near to HV
Apparatus on the Implementing Safety Co-ordinator’s System. It does not apply to other
situations to which OC8A applies. In this part of OC8A, a Permit for Work for proximity
work is to be used, rather then the usual RISSP procedure, given the nature and effect of
the work, all as further provided in the OC8A.8.
OC8A.8.1
Agreement Of Safety Precautions
OC8A.8.1.1
The Requesting Safety Co-ordinator who requires Safety Precautions on another
System(s) when work is to be carried out at an E&W User’s Site or a Transmission Site
(as the case may be) on equipment of the User or the Relevant E&W Transmission
Licensee, as the case may be, where the work or equipment is near to HV Apparatus on
the Implementing Safety Co-ordinator’s System will contact the relevant Implementing
Safety Co-ordinator(s) to agree the Location of the Safety Precautions to be established,
having as part of this process informed the Implementing Safety Co-ordinator of the
equipment and the work to be undertaken. The respective Safety Co-ordinators will ensure
that they discuss the request with their authorised site representative and that the respective
authorised site representatives discuss the request at the Connection Site (or, in the case
of OTSUA, Transmission Interface Site). This agreement will be recorded in the
respective Safety Logs.
OC8A.8.1.2
It is the responsibility of the Implementing Safety Co-ordinator, working with his authorised
site representative as appropriate, to ensure that adequate Safety Precautions are
established and maintained, on his and/or another System connected to his System, to
enable Safety From The System to be achieved for work to be carried out at an E&W
User’s Site or a Transmission Site (as the case may be) on equipment and in relation to
work which is to be identified in the relevant part of the Permit for Work for proximity work
where the work or equipment is near to HV Apparatus of the Implementing Safety Coordinator’s System specified by the Requesting Safety Co-ordinator. Reference to
another System in this OC8A.8.1.2 shall not include the Requesting Safety Co-ordinator’s
System.
OC8A.8.1.3
In The Event Of Disagreement
In any case where the Requesting Safety Co-ordinator and the Implementing Safety Coordinator are unable to agree the Location of the Isolation and (if requested) Earthing,
both shall be at the closest available points on the infeeds to the HV Apparatus near to
which the work is to be carried out as indicated on the Operation Diagram.
OC8A.8.2
Implementation Of Isolation And Earthing
OC8A.8.2.1
Following the agreement of the Safety Precautions in accordance with OC8A.8.1 the
Implementing Safety Co-ordinator shall then establish the agreed Isolation and (if
required) Earthing.
OC8A.8.2.2
The Implementing Safety Co-ordinator shall confirm to the Requesting Safety Coordinator that the agreed Isolation and (if required) Earthing has been established.
OC8A.8.2.3
The Implementing Safety Co-ordinator shall ensure that the established Safety
Precautions are maintained until requested to be removed by the relevant Requesting
Safety Co-ordinator.
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OC8A.8.3
Permit For Work For Proximity Work Issue Procedure
OC8A.8.3.1
Where Safety Precautions on another System(s) are being provided to enable work to be
carried out at an E&W User’s Site or Transmission Site (as the case may be) on
equipment where the work or equipment is in proximity to HV Apparatus of the
Implementing Safety Co-ordinator, before any work commences they must be recorded by
a Permit for Work for proximity work being issued. The Permit for Work for proximity
work shall identify the Implementing Safety Co-ordinator’s HV Apparatus in proximity to
the required work.
OC8A.8.3.2
Once the Safety Precautions have been established (in accordance with OC8A.8.2), the
Implementing Safety Co-ordinator shall agree to the issue of the Permit for Work for
proximity work with the appropriately authorised site representative of the Requesting
Safety Co-ordinator’s Site. The Implementing Safety Co-ordinator will inform the
Requesting Safety Co-ordinator of the Permit for Work for proximity work identifying
number.
OC8A.8.3.3
The appropriately authorised site representative of the Implementing Safety Co-ordinator
shall then issue the Permit for Work for proximity work to the appropriately authorised site
representative of the Requesting Safety Co-ordinator. The Permit for Work for proximity
work will in the section dealing with the work to be carried out, be completed to identify that
the work is near the Implementing Safety Co-ordinator’s HV Apparatus. No further
details of the Requesting Safety Co-ordinator’s work will be recorded, as that is a matter
for the Requesting Safety Co-ordinator in relation to his work.
OC8A.8.3.4
The Requesting Safety Co-ordinator is then free to authorise work in accordance with the
requirements of the relevant internal safety procedures which apply to the Requesting
Safety Co-ordinator’s Site. This is likely to involve the issue of safety documents or other
relevant internal authorisations.
OC8A.8.4
Permit For Work For Proximity Work Cancellation Procedure
OC8A.8.4.1
When the Requesting Safety Co-ordinator decides that Safety Precautions are no longer
required, he will contact the relevant Implementing Safety Co-ordinator to effect
cancellation of the associated Permit for Work for proximity work.
OC8A.8.4.2
The Requesting Safety Co-ordinator will inform the relevant Implementing Safety Coordinator of the Permit for Work for proximity work identifying number, and agree that the
Permit for Work for proximity work can be cancelled. The cancellation is then effected by
the appropriately authorised site representative of the Requesting Safety Co-ordinator
returning the Permit for Work for proximity work to the appropriately authorised site
representative of the Implementing Safety Co-ordinator.
OC8A.8.4.3
The Implementing Safety Co-ordinator is then free to arrange the removal of the Safety
Precautions, the procedure to achieve that being entirely an internal matter for the party the
Implementing Safety Co-ordinator is representing.
OC8A.9
LOSS OF INTEGRITY OF SAFETY PRECAUTIONS
OC8A.9.1
In any instance when any Safety Precautions may be ineffective for any reason the relevant
Safety Co-ordinator shall inform the other Safety Co-ordinator(s) without delay of that
being the case and, if requested, of the reasons why.
OC8A.10
SAFETY LOG
OC8A.10.1
The Relevant E&W Transmission Licensee and E&W Users shall maintain Safety Logs
which shall be a chronological record of all messages relating to safety co-ordination under
OC8A sent and received by the Safety Co-ordinator(s). The Safety Logs must be retained
for a period of not less than one year.
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APPENDIX A - RISSP-R
[the Relevant E&W Transmission Licensee]
[__________________ CONTROL CENTRE/SITE]
RECORD OF INTER-SYSTEM SAFETY PRECAUTIONS (RISSP-R)
(Requesting Safety Co-ordinator's Record)
RISSP NUMBER
PART 1
1.1
HV APPARATUS IDENTIFICATION
Safety Precautions have been established by the Implementing Safety Co-ordinator (or by another User on that User's
System connected to the Implementing Safety Co-ordinator's System) to achieve (in so far as it is possible from that side of
the Connection Point/Transmission Interface Point) Safety From The System on the following HV Apparatus on the
Requesting Safety Co-ordinator's System: [State identity - name(s) and, where applicable, identification of the HV circuit(s)
up to the Connection Point/Transmission Interface Point]:
______________________________________________________________________________________________
______________________________________________________________________________________________
Further Safety precautions required on the Requesting Safety Co-ordinator’s System as notified by the Implementing
Safety Co-ordinator.
______________________________________________________________________________________________
1.2
SAFETY PRECAUTIONS ESTABLISHED
(a)
ISOLATION
[State the Location(s) at which Isolation has been established (whether on the Implementing Safety Co-ordinator's System
or on the System of another User connected to the Implementing Safety Co-ordinator's System). 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, Caution Notice affixed, other safety procedures applied, as appropriate.]
______________________________________________________________________________________________
______________________________________________________________________________________________
______________________________________________________________________________________________
(b)
EARTHING
[State the Location(s) at which Earthing has been established (whether on the Implementing Safety Co-ordinator's System
or on the System of another User connected to the Implementing Safety Co-ordinator's System). For each Location,
identify each point of Earthing. For each point of Earthing, state the means by which Earthing has been achieved, and
whether, immobilised and Locked, other safety procedures applied, as appropriate].
______________________________________________________________________________________________
______________________________________________________________________________________________
______________________________________________________________________________________________
1.3
ISSUE
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 Co-ordinator)
at .......................................(time) on .................................................. (Date)
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PART 2
2.1
CANCELLATION
l have confirmed to _________________________________________ (name of the Implementing Safety Co-ordinator) 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 Co-ordinator)
at ........................................(time) on ................................................. (Date)
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APPENDIX B - RISSP-I
[the Relevant E&W Transmission Licensee]
[_________________ CONTROL CENTRE/SITE]
RECORD OF INTER-SYSTEM SAFETY PRECAUTIONS (RISSP-I)
(Implementing Safety Co-ordinator's Record)
PART 1
1.1
RISSP NUMBER
HV APPARATUS IDENTIFICATION
Safety Precautions have been established by the Implementing Safety Co-ordinator (or by another User on that User's
System connected to the Implementing Safety Co-ordinator's System) to achieve (in so far as it is possible from that side of
the Connection Point/Transmission Interface Point) Safety From The System on the following HV Apparatus on the
Requesting Safety Co-ordinator's System: [State identity - name(s) and, where applicable, identification of the HV circuit(s)
up to the Connection Point/Transmission Interface Point]:
______________________________________________________________________________________________
______________________________________________________________________________________________
Recording of notification given to the Requesting Safety Co-ordinator concerning further Safety Precautions required on the
Requesting Safety Co-ordinator’s System.
1.2
SAFETY PRECAUTIONS ESTABLISHED
(a)
ISOLATION
[State the Location(s) at which Isolation has been established (whether on the Implementing Safety Co-ordinator's System
or on the System of another User connected to the Implementing Safety Co-ordinator's System). 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, Caution Notice affixed, other safety procedures applied, as appropriate.]
______________________________________________________________________________________________
______________________________________________________________________________________________
______________________________________________________________________________________________
(b)
EARTHING
[State the Location(s) at which Earthing has been established (whether on the Implementing Safety Co-ordinator's System
or on the System of another User connected to the Implementing Safety Co-ordinator's System). For each Location,
identify each point of Earthing. For each point of Earthing, state the means by which Earthing has been achieved, and
whether, immobilised and Locked, other safety procedures applied, as appropriate].
______________________________________________________________________________________________
______________________________________________________________________________________________
______________________________________________________________________________________________
1.3
ISSUE
I have confirmed to ________________________________________ (name of Requesting Safety Co-ordinator) 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 Co-ordinator)
at ...............................................(time) on ...................................................... (Date)
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PART 2
2.1
CANCELLATION
l 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 Co-ordinator)
at ................................................(time) on ........................................................ (Date)
(Note: This form to be of a different colour from RISSP-R)
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APPENDIX C - FLOWCHARTS
APPENDIX C1 - RISSP ISSUE PROCESS
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APPENDIX C2 - TESTING PROCESS
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APPENDIX C3 - RISSP CANCELLATION PROCESS
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APPENDIX C4 - PROCESS FOR WORKING NEAR TO SYSTEM EQUIPMENT
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APPENDIX D - NATIONAL GRID SAFETY CIRCULAR
National Grid Safety Circular
(NGSC)
NGSC Number:
RISSP prefixes - Issue x
Date:
Issued By:
..........................
Example
Pursuant to the objectives of The Grid Code, Operating Code 8A1 - Safety Co-ordination, this circular will be
used in relation to all cross boundary safety management issues with the Relevant E&W Transmission
Licensee customers. Of particular note will be the agreed prefixes for the Record of Inter System Safety
Precautions (RISSP) documents.
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APPENDIX E - FORM OF NGET PERMIT TO WORK
[Form of the Relevant E&W Transmission Licensee Permit for Work]
No.
PERMIT FOR WORK
1.
Location……………………………………………………………..………………………………………………………………
Equipment Identification………………………………….………………………………………………………………………
………………………………………………………………………………………………………………………………………
Work to be done
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
2.
Precautions taken to achieve Safety from the System
Points of Isolation
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
Primary Earths
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
Actions taken to avoid Danger by draining, venting, purging and containment or dissipation of stored energy*
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
Further precautions to be taken during the course of the work to avoid System derived hazards*
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
3.
Precautions that may be varied*
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………………………
4.
Preparation
Control Person(s) (Safety) giving Consent
Key Safe number*
State whether this Permit for Work must be personally retained yes
Signed
no
Time
Date
Senior Authorised Person
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5.
Issue & Receipt
Key Safe Number*
Safety Keys (No. off)*
Earthing Schedule Number*
Portable Drain earths (No. off)*
Recommendations for General
Safety Report Number*
Approved (ROMP)#/Card Safe#/
Procedure Number*
Circuit Identification – Colours/
Symbols*
Flags (No. off)*
Wristlets (No. off)*
Issued (Signed)
Senior Authorised Person
Received (Signed)
Time
Date
Competent Person
Name (Block letters)
Company
# delete as appropriate *write N/A if not applicable
February 1995
< END OF OPERATING CODE NO. 8 APPENDIX 1>
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OPERATING CODE NO. 8 APPENDIX 2
(OC8B)
SAFETY CO-ORDINATION IN RESPECT OF THE SCOTTISH TRANSMISSION
SYSTEMS OR THE SYSTEMS OF SCOTTISH USERS
CONTENTS
(This contents page does not form part of the Grid Code)
Paragraph No/Title
Page Number
OC8B.1 INTRODUCTION ................................................................................................................................3
OC8B.2 OBJECTIVE ........................................................................................................................................6
OC8B.3 SCOPE ...............................................................................................................................................6
OC8B.4 PROCEDURE .....................................................................................................................................6
OC8B.4.1 Approval Of Safety Rules .........................................................................................................6
OC8B.4.2 Safety Co-ordinators ................................................................................................................7
OC8B.4.3 RISSP.......................................................................................................................................7
OC8B.5 SAFETY PRECAUTIONS ON HV APPARATUS................................................................................8
OC8B.5.1 Agreement Of Safety Precautions............................................................................................8
OC8B.5.2 Implementation Of Isolation .....................................................................................................9
OC8B.5.3 Implementation of Earthing ....................................................................................................10
OC8B.5.4 RISSP Issue Procedure .........................................................................................................10
OC8B.5.5 RISSP Cancellation Procedure ..............................................................................................11
OC8B.5.6 RISSP Change Control ..........................................................................................................13
OC8B.6 TESTING ..........................................................................................................................................13
OC8B.7 EMERGENCY SITUATIONS ............................................................................................................13
OC8B.8 SAFETY PRECAUTIONS RELATING TO WORKING ON EQUIPMENT NEAR TO THE HV
SYSTEM ...........................................................................................................................................................14
OC8B.8.1 Agreement Of Safety Precautions..........................................................................................14
OC8B.8.2 Implementation Of Isolation And Earthing..............................................................................15
OC8B.8.3 Permit For Work For Proximity Work Issue Procedure .........................................................15
OC8B.8.4 Permit For Work For Proximity Work.....................................................................................15
OC8B.9 LOSS OF INTEGRITY OF SAFETY PRECAUTIONS ......................................................................16
OC8B.10 SAFETY LOG .................................................................................................................................16
APPENDIX A - RISSP-R ..................................................................................................................................17
APPENDIX B - RISSP-I ....................................................................................................................................19
APPENDIX C- FLOWCHARTS ........................................................................................................................21
APPENDIX C1 - RISSP ISSUE PROCESS ..............................................................................................21
APPENDIX C2 - TESTING PROCESS.....................................................................................................22
APPENDIX C3 - RISSP CANCELLATION PROCESS .............................................................................23
APPENDIX C4 - PROCESS FOR WORKING NEAR TO SYSTEM EQUIPMENT...................................24
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APPENDIX D - NOT USED ..............................................................................................................................25
APPENDIX E - FORM OF PERMIT TO WORK ...............................................................................................26
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OC8B.1
INTRODUCTION
OC8B.1.1
OC8B specifies the standard procedures to be used by NGET, the Relevant Scottish
Transmission Licensees and Scottish Users for the co-ordination, establishment and
maintenance of necessary Safety Precautions when work is to be carried out on or near the
Scottish Transmission System or the System of a Scottish User and when there is a
need for Safety Precautions on HV Apparatus on the other's System for this work to be
carried out safely. OC8B applies to Relevant Scottish Transmission Licensees and
Scottish Users. Where work is to be carried out on or near equipment on an E&W
Transmission System or the Systems of E&W Users, but such work requires Safety
Precautions to be established on a Scottish Transmission System or the Systems of
Scottish Users, OC8B should be followed by the Relevant Scottish Transmission
Licensee and Scottish Users to establish the required Safety Precautions.
OC8A specifies the procedures to be used by the Relevant E&W Transmission Licensee
and E&W Users.
NGET shall procure that Relevant Scottish Transmission Licensees shall comply with
OC8B where and to the extent that such section applies to them.
In this OC8B the term “work” includes testing, other than System Tests which are covered
by OC12.
OC8B.1.2
OC8B also covers the co-ordination, establishment and maintenance of necessary safety
precautions on the Implementing Safety Co-ordinator’s System when work is to be carried
out at a Scottish User’s Site or a Transmission Site (as the case may be) on equipment of
the Scottish User or the Relevant Scottish Transmission Licensee as the case may be
where the work or equipment is near to HV Apparatus on the Implementing Safety Coordinator’s System. In the case of OTSUA, a Scottish User’s Site or Transmission Site
shall, for the purposes of this OC8B, include a site at which there is a Transmission
Interface Point until the OTSUA Transfer Time and the provisions of this OC8B and
references to OTSUA shall be construed and applied accordingly until the OTSUA Transfer
Time at which time arrangements in respect of the Transmission Interface Site will have
been put in place between the Relevant Scottish Transmission Licensee and the
Offshore Transmission Licensee.
OC8B.1.3
OC8B does not apply to the situation where Safety Precautions need to be agreed solely
between Scottish Users. OC8B does not apply to the situation where Safety Precautions
need to be agreed solely between Transmission Licensees.
OC8B.1.4
OC8B does not seek to impose a particular set of Safety Rules on Relevant Scottish
Transmission Licensees and Scottish Users. The Safety Rules to be adopted and used
by the Relevant Scottish Transmission Licensee and each Scottish User shall be those
chosen by each.
OC8B.1.5
Site Responsibility Schedules document the control responsibility for each item of Plant
and Apparatus for each site.
OC8B.1.6
(a) The Relevant Scottish Transmission Licensee may agree alternative site-specific
operational procedures with Scottish Users for the co-ordination, establishment and
maintenance of Safety Precautions instead of the Record of Inter-System Safety
Precautions (“RISSP”) procedure detailed in this OC8B. Such operational procedures
shall satisfy the requirements of paragraphs OC8B.1.7, OC8B.2.1, OC8B.4.1,
OC8B.4.2, OC8B.9, OC8B.10. These alternative site-specific operational procedures for
the co-ordination, establishment and maintenance of Safety Precautions will be
referenced in the relevant Site Responsibility Schedule.
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(b) The Relevant Scottish Transmission Licensee may agree with Scottish Users sitespecific procedures for the application of Safety Precautions across the interface
between Relevant Scottish Transmission Licensee and Scottish User in addition to
and consistent with either the RISSP procedure or the alternative site-specific
operational procedures described in OC8B.1.6 (a). These site-specific procedures will
be referenced in the relevant Site Responsibility Schedule.
(c) The Relevant Scottish Transmission Licensee and the Scottish User shall comply
with the procedures agreed pursuant to OC8B.1.6 (a) and OC8B.1.6 (b).
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OC8B.1.7
Defined Terms
OC8B.1.7.1
Scottish Users should bear in mind that in OC8 only, in order that OC8 reads more easily
with the terminology used in certain Safety Rules, the term "HV Apparatus" is defined more
restrictively and is used accordingly in OC8B. Scottish Users should, therefore, exercise
caution in relation to this term when reading and using OC8B.
OC8B.1.7.2
In OC8 only the following terms shall have the following meanings:
(1) "HV Apparatus" means High Voltage electrical circuits forming part of a System, on
which Safety From The System may be required or on which Safety Precautions may
be applied to allow work to be carried out on a System.
(2) "Isolation" means the disconnection of Apparatus from the remainder of the System in
which that Apparatus is situated by either of the following:
(a) an Isolating Device maintained in an isolating position. The isolating position must
either be:
(i)
maintained by immobilising and Locking the Isolating Device in the isolating
position and affixing a Caution Notice to it. Where the Isolating Device is
Locked with a Safety Key, the Safety Key must be secured in a Key Safe
and the Key Safe Key must be given to the authorised site representative of
the Requesting Safety Co-ordinator where reasonably practicable and is to
be retained in safe custody. Where not reasonably practicable the Key Safe
Key must be retained by the authorised site representative of the
Implementing Safety Co-ordinator in safe custody; or
(ii)
maintained and/or secured by such other method which must be in
accordance with the Safety Rules of the Relevant Scottish Transmission
Licensee or that Scottish User, as the case may be; or
(b) an adequate physical separation which must be in accordance with, and maintained
by, the method set out in the Safety Rules of the Relevant Scottish
Transmission Licensee or that Scottish User, as the case may be, and, if it is a
part of that method, a Caution Notice must be placed at the point of separation; or
(c) in the case where the relevant HV Apparatus of the Implementing Safety Coordinator is being either constructed or modified, an adequate physical separation
as a result of a No System Connection.
(3) “No System Connection” means an adequate physical separation (which must be in
accordance with, and maintained by, the method set out in the Safety Rules of the
Implementing Safety Co-ordinator) of the Implementing Safety Co-ordinator’s HV
Apparatus from the rest of the Implementing Safety Co-ordinator’s System where
such HV Apparatus has no installed means of being connected to, and will not for the
duration of the Safety Precaution be connected to, a source of electrical energy or to
any other part of the Implementing Safety Co-ordinator’s System.
(4) "Earthing" means a way of providing a connection between conductors and earth by an
Earthing Device which is either:
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(i)
immobilised and Locked in the earthing position. Where the Earthing Device is
Locked with a Safety Key, the Safety Key must be secured in a Key Safe and the
Key Safe Key must be given to the authorised site representative of the
Requesting Safety Co-ordinator where reasonably practicable and is to be
retained in safe custody. Where not reasonably practicable the Key Safe Key must
be retained by the authorised site representative of the Implementing Safety Coordinator in safe custody; or
(ii)
maintained and/or secured in position by such other method which must be in
accordance with the Safety Rules of the Relevant Scottish Transmission
Licensee or that Scottish User as the case may be.
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OC8B.1.7.3
For the purpose of the co-ordination of safety relating to HV Apparatus the term “Safety
Precautions” means Isolation and/or Earthing.
OC8B.2
OBJECTIVE
OC8B.2.1
The objective of OC8B is to achieve:(i)
Safety From The System when work on or near a System necessitates the provision of
Safety Precautions on another System on HV Apparatus up to a Connection Point
(or, in the case of OTSUA, Transmission Interface Point); and
(ii)
Safety From The System when work is to be carried out at a Scottish User’s Site or a
Transmission Site (as the case may be) on equipment of the Scottish User or the
Relevant Scottish Transmission Licensee (as the case may be) where the work or
equipment is near to HV Apparatus on the Implementing Safety Co-ordinator’s
System.
OC8B.2.2
A flow chart, set out in OC8B Appendix C, illustrates the process utilised in OC8B to achieve
the objective set out in OC8B.2.1. In the case of a conflict between the flow chart and the
provisions of the written text of OC8B, the written text will prevail.
OC8B.3
SCOPE
OC8B.3.1
OC8B applies to NGET, Relevant Scottish Transmission Licensees and to Scottish
User