NORTHERN IRELAND ELECTRICITY PLC
DISTRIBUTION CODE
1 MAY 2010
Introduction
1 The Distribution Code is designed to permit the development, maintenance and
operation of an efficient, co-ordinated and economical Distribution System and
generally to facilitate competition in the generation and supply of electricity. It is
conceived as a statement of what is optimal (particularly from a technical point of view)
for all Users and the DNO itself in relation to the planning, operation and use of the
Distribution System. It seeks to avoid any undue discrimination between Users and
categories of Users.
2 The operating procedures and principles governing the DNO’s relationship with all
Users of the Distribution System, be they Generators, Suppliers, or Demand
Customers, are set out in the Distribution Code. The Distribution Code specifies
day-to-day procedures for both planning and operational purposes and covers both
normal and exceptional circumstances.
3 The Distribution Code is divided into the following sections:-
(a) a Planning Code which provides generally for the supply of certain information
by Users in order that the planning and development of the Distribution System
may be undertaken;
(b) Connection Conditions which specify the minimum technical, design and
certain operational criteria which must be complied with by Users connected to
or seeking connection with the Distribution System;
(c) an Operating Code which is split into a number of sections and deals with:-
(i) Generation and Demand forecasting (OC1);
(ii) the co-ordination of the Outage planning process in respect of
Generating Units and Power Station Equipment and Outages of
equipment on the Distribution System for construction, repair and
maintenance (OC2);
(iii) different methods of reducing Demand (OC3);
(iv) the reporting between the DNO and Users of scheduled and planned
actions and unexpected occurrences such as faults (OC4);
(v) the provision of written reports on occurrences such as faults in certain
circumstances (OC5);
(vi) the co-ordination, establishment and maintenance of Isolation and
Earthing in order that work and/or testing can be carried out safely
(OC6);
(vii) certain aspects of contingency planning (OC7);
(viii) the procedures for determining the number and nomenclature of Plant
and Apparatus at Connection Sites (OC8);
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Introduction Page 2
(ix) the procedures for the establishment of System Tests (OC9); and
(x) Testing, Monitoring and Investigations in relation to User’s Plant and
Apparatus (OC10);
(d) General Conditions which are intended to ensure, so far as possible, that the
various sections of the Distribution Code work together and work in practice
and which include provisions relating to the establishment of a Distribution
Code Review Panel and other provisions of a general nature; and
(e) a Distribution Metering Code which deals with the basic requirements for
metering.
4 A matrix is provided as Appendix 1 to this section which sets out, for information only,
a guide to the applicability of each section of the Distribution Code to different
categories of Users. It is, however, for each User to review the relevant sections of the
Distribution Code to decide itself with which sections it must comply.
5 This Introduction is provided to Users and to prospective Users for information only
and does not constitute part of the Distribution Code
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Introduction Page 3
Appendix 1
This matrix provides, for information only, a guide to the applicability of each section of the Distribution Code to different categories of Users. It
is, however, for each User to review the relevant sections of the Distribution Code to decide itself with which sections it must comply.
GC PC CC OC1 OC2 OC3 OC4 OC5 OC6 OC7 OC8 OC9 OC10 MC
Generator with a CDGU
Generator with a Controllable WFPS
Generator with a connection at 33kV
Generator with a connection at 11kV
Generator with a connection at 6.6kV
Generators with a rating of 70kVA and above
Generator with Independent Generating Plant >1MW
Suppliers
Demand Customer
Demand Customer with a connection at 33kV
Demand Customer with a connection at 11kV
Demand Customer with a connection at 6.6kV
Demand Customer >1MW
Demand Customer >10MW
Demand Customer ≥70kVA
– Users in this category have relevant information but no specific obligations set out in this section.
– Users in this category have specific obligations set out in this section.
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General Conditions
1 Introduction
1.1 The General Conditions contain provisions which are of general application to all
sections of the Distribution Code. Their objective is to ensure, to the extent possible,
that the various sections of the Distribution Code work together and work in practice
for the benefit of all Users.
2 Scope
2.1 The General Conditions apply to the DNO and to all Users. The term “Users” in
these General Conditions means all persons (other than the DNO and the TSO)
referred to in any individual section of the Distribution Code is expressed to apply.
2.2 Some Users whose Plant and Apparatus are connected to the Distribution System
may also be required to comply with the Grid Code. Users should therefore check the
Grid Code to see whether they are required to comply with the Grid Code as well as
the Distribution Code. It is intended by the DNO that there should be no provision in
the Distribution Code which would require a User to act in a way which would require
it to be in breach of its Grid Code obligations.
2.3 The Distribution Code affects any person whose Plant and/or Apparatus is connected
to the Distribution System or who otherwise uses the Distribution System, even
where they are not expressed to be “Users” under any individual section of the
Distribution Code. Anything done by the DNO under or pursuant to the Distribution
Code which affects, or which may affect such persons, shall be deemed to be
undertaken under the Distribution Code in relation to those persons.
3 Assistance in Implementation
3.1 The Licence held by the DNO imposes a duty upon the DNO to implement the
Distribution Code and it is accepted by the DNO and all Users that the Distribution
Code must, therefore, be capable of being enforced by the DNO. In certain cases the
DNO may need access across boundaries, services and facilities from Users or to issue
instructions to Users in order to be able to implement and enforce the Distribution
Code. It is hoped that these cases would be exceptional and it is not, therefore, possible
to envisage precisely or comprehensively what the DNO might reasonably require in
order to put it in a position to be able to carry out its duty to implement and enforce the
Distribution Code, in these cases.
3.2 Accordingly, all Users are required not only to abide both by the letter and the spirit of
the Distribution Code, but also to provide the DNO with such rights of access,
services and facilities and to comply with such instructions as it may reasonably require
to implement and enforce the Distribution Code.
4 Unforeseen Circumstances
4.1 If circumstances arise which the provisions of the Distribution Code have not
foreseen, the DNO shall, to the extent reasonably practicable in the circumstances,
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consult promptly and in good faith all affected Users in an effort to reach agreement as
to what action should be taken. If agreement between the DNO and such Users cannot
be reached in the time available, the DNO shall determine what is to be done.
Whenever the DNO makes a determination, it shall do so having regard, wherever
possible, to the views expressed by Users and, in any event, to what is reasonable in all
the circumstances. Each User shall comply with all instructions given to it by the DNO
following such a determination provided that the instructions are consistent with the
then current technical parameters of the relevant User’s System registered under the
Distribution Code. The DNO shall, as soon as reasonably practicable following the
occurrence of unforeseen circumstances, notify all relevant details thereof to the Panel
for consideration in accordance with paragraph 6.2 (e).
5 Hierarchy
5.1 In the event of any conflict between the provisions of any direction of the Secretary of
State or the Minister on the one hand and any provisions of the Distribution Code on
the other, the provisions of such direction shall prevail (provided that such direction or
ruling is binding upon the person to whom it is addressed), and neither the DNO nor
any User shall be liable for failing to comply with the conflicting provision of the
Distribution Code.
5.2 In the event of any conflict between the provisions of the Distribution Code unless
otherwise specified and any contract, agreement or arrangement between the DNO and
a User, the provisions of the Distribution Code shall prevail unless the Distribution
Code expressly provides otherwise.
6 The Distribution Code Review Panel
6.1 The DNO shall establish and maintain the Panel, which shall be a standing body
carrying out the functions referred to in paragraph 6.2.
6.2 The Panel shall:
(a) keep the Distribution Code and its working under review;
(b) review all suggestions for amendments to the Distribution Code which the
Authority or any User may submit to the DNO for consideration by the Panel
from time to time;
(c) determine recommendations for amendments to the Distribution Code which
the DNO or the Panel feels are necessary or desirable and the reasons for the
recommendations;
(d) issue guidance in relation to the Distribution Code and its implementation,
performance and interpretation upon the reasonable request of any User; and
(e) consider what changes are necessary to the Distribution Code arising out of any
unforeseen circumstances referred to it by the DNO under paragraph 4.1.
6.3 The Panel shall consist of the following persons, each of whom shall have the right to
vote:-
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(a) a chairman appointed by the DNO;
(b) four persons representing the DNO;
(c) three persons representing Generators;
(d) one person representing Demand Customers with large energy usage;
(e) three persons representing electricity Suppliers; and
(f) one person appointed by and representing the Authority.
6.4 The Chairman may invite a representative of the TSO to attend meetings of the Panel.
6.5 The Panel shall establish and comply at all times with its own rules and procedures
relating to the conduct of its business, which shall be approved by the Authority.
6.6 The DNO shall submit all proposed amendments to the Distribution Code (regardless
of which party proposes such amendment) to the Panel for discussion prior to fulfilling
any obligations under its Licence in relation to wider consultation.
7 Communication between the DNO and Users
7.1 Unless otherwise specified in the Distribution Code, all instructions given by the DNO
and communications (other than those relating to the submission of data and notices)
between the DNO and Users (other than Generators) shall take place between the Duty
Shift Manager and the relevant User’s Responsible Engineer/Operator or such other
person as the DNO or the User (as the case may be) may from time to time notify to
the other for such purposes.
7.2 Unless otherwise specified in the Distribution Code, all instructions given by the DNO
and communications (other than those relating to the submission of data and notices)
between the DNO and a Generator shall take place between the Duty Shift Manager
and the Generator’s Power Station Manager or such other person as the DNO or the
Generator (as the case may be) may from time to time notify to the other for such
purposes.
7.3 Unless otherwise specified in the Distribution Code, all instructions given by the DNO
and communications (other than relating to the submission of data and notices which
shall be submitted pursuant to paragraph 8.2) between the DNO and Users will be by
means of telephone with a facility to record messages permanently or by electronic mail
(using only e-mail addresses which have either been previously communicated to the
User by the DNO or to the DNO by the User.). Any responses required to a
communication shall make use of the same means, telephone with a facility to record
messages permanently or by electronic mail, as the original communication.
7.4 Where instructions or communications are given under the Distribution Code by
means of a communications system with a facility to record (by whatever means)
messages permanently, such recording shall be accepted by the DNO and Users as
evidence of those instructions or communications.
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8 Data and Notices
8.1 Data collected by, or otherwise passed to, the DNO under the Distribution Code may
be given to the TSO under the Grid Code or under the Transmission Interface
Agreement, where the DNO is required or permitted to pass that data across.
8.2 Data and notices to be submitted to the DNO under the Distribution Code (other than
data which is the subject of a specific requirement of the Distribution Code as to the
manner of its delivery) shall be delivered in writing either by hand or sent by registered
first class pre-paid post, or by facsimile transmission, or by electronic mail (using only
an e-mail address which has been previously communicated to the User by the DNO).
8.3 Data delivered pursuant to paragraph 8.2 shall:
(a) in the case of data to be submitted by a User prior to the connection of its Plant
and/or Apparatus to the Distribution System, in relation to that Plant and/or
Apparatus, be addressed to the Network Risk and Investment Manager at the
address notified by the DNO to the User following receipt of an application for
connection to the Distribution System, or to such other department within the
DNO or address as the DNO may notify to the User from time to time; and
(b) in the case of data to be submitted by a User in respect of Plant and/or
Apparatus connected to the Distribution System, be addressed to the
Distribution Service Centre Manager at the address notified by the DNO to the
User prior to connection to the Distribution System, or to such other
department within the DNO or address as the DNO may notify to the User from
time to time.
8.4 Notices submitted to Users shall be addressed to such person as may be notified in
writing to the DNO from time to time by the relevant User at its address(es) notified by
the User to the DNO in writing from time to time for submission of data and service of
notices under the Distribution Code (or failing which to the registered or principal
office of the User).
8.5 Where applicable all data items will be referenced to nominal voltage and Frequency
unless otherwise stated.
9 Ownership of Plant and/or Apparatus
References in the Distribution Code to Plant and/or Apparatus of a User include
Plant and/or Apparatus used by a User under any agreement with a third party.
10 Emergency Situations
Users should note that the provisions of the Distribution Code may be suspended in
whole or in part pursuant to any directions given and/or orders made by the Secretary
of State under Article 58 of the Order.
11 Illegality and Partial Invalidity
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If any provision of the Distribution Code should become or be declared unlawful or
partially invalid for any reason, the validity of all remaining provisions of the
Distribution Code shall not be affected. If part of a provision of the Distribution Code
is invalid or unlawful but the rest of such provision would remain valid if part of the
wording were deleted, the provision shall apply with such modifications as may be
necessary to make it valid and effective but without affecting the meaning or validity of
any other provision of the Distribution Code.
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Planning Code
1 Introduction
1.1 The Planning Code (“PC”) specifies the requirements for the supply of information to
the DNO by persons connected or persons seeking a new or modified connection to the
Distribution System in order to enable the planning and development of the
Distribution System and, where required, the co-ordinated planning and development
of the Transmission System.
1.2 It also specifies the technical and design criteria and procedures to be applied in the
planning and development of the Distribution System and to be taken account of by
persons connected or seeking connection to the Distribution System in the planning
and development of their own Systems.
1.3 The DNO has obligations under the Grid Code planning code to provide data to the
TSO in order for the development of the Transmission System to be planned. Certain
information received by the DNO from Users under this PC may be passed on to the
TSO in accordance with the DNO’s obligations under the Grid Code.
1.4 System developments must be planned with sufficient lead time to allow any necessary
consents to be obtained and detailed engineering design and construction works to be
completed. Therefore, the PC and the relevant Connection Agreement impose
appropriate timescales on the exchange of information between the DNO and Users
subject to all parties having regard, where appropriate, to the confidentiality of such
information
2 Objectives
2.1 The objectives of the PC are to:-
(a) provide for the supply of information from Users to the DNO which is required
by the DNO in order for the development (including reinforcement and
extension) of the Distribution System to be planned;
(b) provide for the supply of information from Users to the DNO which is required
by both the DNO and the TSO in order to enable the planning and development
of the Transmission System;
(c) reflect the Licence requirements for the supply of information from the DNO to
Users in the form of Statements on Distribution System Capacity;
(d) set out the requirements for the supply of information from Users to the DNO in
respect of any proposed development on a User’s System which may impact on
the performance of the Distribution System or the Transmission System; and
(e) specify the technical and design criteria and procedures which will be applied by
the DNO in the planning and development of the Distribution System and
which are to be taken into account by Users in the planning and development of
their own Systems.
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3 Scope
3.1 The PC applies to the DNO and to Users, which in the PC means:-
(a) Generators in respect of their Plant and/or Apparatus connected to the
Distribution System;
(b) Suppliers; and
(c) Demand Customers in respect of their Connection Sites with a Demand of
1MW and above.
3.2 Persons whose prospective activities would place them in any of the above categories of
User will, as a result of the application procedure for a Connection Agreement,
become subject to the PC prior to their generating, supplying or consuming electricity,
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.
4 Categories of planning data
4.1 Planning data required under the PC from Users is allocated to one of two categories:-
(a) Standard Planning Data; and
(b) Detailed Planning Data.
4.2 Lists of Standard Planning Data and Detailed Planning Data are set out in
Appendices A and B to this PC.
5 Manner of provision by Users
5.1 All data to be supplied by Users to the DNO pursuant to this PC shall reflect the best
possible estimate or measurement available to the User in the circumstances, shall be
supplied in writing by the date specified for the purpose of the PC or, where no date is
so specified, in a prompt and timely manner. The DNO shall be entitled to require any
User to submit further information in the event that it considers any data supplied to it
by such User to be unclear or incomplete.
5.2 Failure by a User to comply with its obligation under paragraph 5.1 may result in the
Distribution System, and, in certain circumstances, the Transmission System, being
planned in accordance with incorrect data and/or a delay in the offer of terms being
made to the User by the DNO for connection.
6 Distribution System Planning Criteria
The DNO shall ensure that the relevant Licence Standards are applied in the planning
and development of the Distribution System and these shall be taken into account by
Users in the planning and development of their own Systems.
7 Statement on Distribution System Capacity
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7.1 By way of information for Users, and generally without imposing any other or further
obligation to that contained in the Licence of the DNO, this paragraph 7 sets out a brief
description of the position regarding the provision by the DNO to Users of Statements
on Distribution System Capacity.
7.2 One of the means by which Users and intending Users are able to assess available
Distribution System capacity is the Statement on Distribution System Capacity,
prepared by the DNO under its Licence where requested by any person, showing
present and future circuit capacity, forecast power flows and loading on the part or
parts of the Distribution System specified in the request and fault levels for each
network node covered by the request.
7.3 A Distribution System Capacity Statement will, unless the DNO is relieved of its
obligation by the Authority pursuant to its Licence, be prepared if requested by any
person and the DNO will, subject to paragraph 7.4, give or send such statement to the
person making the request. Where a User requested a Distribution System Capacity
Statement the User must provide sufficient information to the DNO to enable the
statement to be made, including, but not limited to, the relevant Standard Planning
Data. The statement shall, in addition to those matters set out in paragraph 7.2 include:
7.3.1 such further information as shall be reasonably necessary to enable the person
requesting it to identify and evaluate the opportunities available when connecting
to and making use of the part or parts of the Distribution System specified in
the request; and
7.3.2 if so required, a commentary prepared by the DNO indicating its view as to the
suitability of the part or parts of the Distribution System specified in the
request for new connections and transport of further quantities of electricity.
7.4 The DNO may within 10 days after receipt of the request for a Distribution System
Capacity Statement provide the requester with an estimate of its reasonable costs in
the preparation of the statement and the provision of the statement under paragraph 7.3
shall be conditional upon the person requesting the statement agreeing to pay the charge
(or such other amount as the Authority may direct). The statement shall be given or
sent within 28 days (or, where the Authority so approves, such longer period as the
DNO may reasonably request, having regard to the nature and complexity of the
request) of the later of the date of receipt of the request or the date on which the DNO
receives agreement from the requester to pay the charge estimated or the date on which
the amount is determined by the Authority. Where no charge is to be levied, the
statement shall be given or sent within 28 days of the receipt of the request.
8 Status of Planning Data
8.1 For Planning Code purposes, planning data supplied by Users is allocated to one of
three status levels which provide a progression related to degrees of confidentiality,
commitment and validation, as follows:-
8.2 Preliminary Project Planning Data
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8.2.1 Data supplied by a User in conjunction with an application for connection to the
Distribution System shall be considered as Preliminary Project Planning
Data until such time as a binding Connection Agreement is established
between the DNO and the User.
8.2.2 Subject to paragraph 8.2(c), this data shall not be disclosed by the DNO unless
and until it becomes Committed Project Planning Data and/or Registered
Project Planning Data whereupon the following applicable disclosure
provisions of this paragraph 8 will apply.
8.2.3 The DNO may disclose Preliminary Project Planning Data to the TSO for the
purposes of consideration of developments such as, for example, reinforcement
or upgrading of the Transmission System.
8.2.4 Preliminary Project Planning Data will normally contain only Standard
Planning Data, unless Detailed Planning Data is specifically requested by the
DNO to permit more detailed Distribution System or Transmission System
studies.
8.3 Committed Project Planning Data
When the offer for a Connection Agreement is accepted, the data relating to the
User’s development submitted as Preliminary Project Planning Data and data
required or received subsequently by the DNO under this PC shall have the status of
Committed Project Planning Data. Until such time as Registered Project Planning
Data is received for a new or modified connection to the Distribution System,
Committed Project Planning Data, together with other data held by the DNO relating
to the Distribution System, shall form the background against which new applications
from Users shall be considered and against which planning of the Distribution System
and the Transmission System shall be undertaken. Accordingly, Committed Project
Planning Data may be disclosed by the DNO to the extent that the DNO:-
(a) needs to disclose it in Statements of Distribution System Capacity and in any
further information which the DNO is required to provide together with
Statements of Distribution System Capacity;
(b) needs to disclose it when considering and/or advising on applications (or
possible applications) of Users, including disclosure of it or data from it both
orally and in writing, to other Users making an application (or considering or
discussing a possible application) which is, in the DNO’s view, relevant to that
application or possible application;
(c) needs to disclose it to the TSO for the purposes of the planning and/or the
development of the Transmission System; or
(d) needs to disclose it for operational purposes.
Committed Project Planning Data may contain both Standard Planning Data and
Detailed Planning Data.
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8.4 Registered Project Planning Data
8.4.1 The Connection Conditions require that, before an agreed connection to the
Distribution System may be physically established, any estimated values
contained within the Committed Project Planning Data shall be replaced,
where practicable, by validated actual values and as appropriate by updated
forecasts for future data items such as Demand. Data provided at this stage is
termed Registered Project Planning Data.
8.4.2 Registered Project Planning Data may contain both Standard Planning and
Detailed Planning Data.
8.4.3 Registered Project Planning Data, together with other data held by the DNO
relating to the Distribution System will form the background against which new
applications by any User will be considered and against which planning of the
Distribution System and the Transmission System will be undertaken.
Accordingly, Registered Project Planning Data may be disclosed by the DNO
to the extent that the DNO:-
(a) needs to disclose it in the preparation of Statements of Distribution
System Capacity and in any further information which the DNO is
required to provide together with the Statement of Distribution System
Capacity;
(b) needs to disclose it when considering and/or advising on applications (or
possible applications) of Users, including disclosure of it or data from it
both orally and in writing, to other Users making an application (or
considering or discussing a possible application) which is, in the DNO’s
view, relevant to that application or possible application;
(c) needs to disclose it to the TSO for the purposes of the planning and/or
the development of the Transmission System; or
(d) needs to disclose it for operational purposes.
8.5 For the avoidance of doubt, the DNO may additionally use the data supplied for the
purposes referred to in this PC, in complying with the requirements of its Licence and
for operational purposes and nothing herein shall limit the DNO’s rights to disclose
information pursuant to any provisions relating to confidentiality in any Connection
Agreement or in the Licence held by the DNO.
9 Application for a new or modified Connection Agreement
9.1 Any person seeking to establish a new or modified Connection Agreement pursuant to
the Licence held by the DNO must make application on the standard application form
which is available from the DNO on request. The application shall include:-
(a) a description of the Plant and/or Apparatus to be connected to the Distribution
System or, as the case may be, of the modification relating to the User’s Plant
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and/or Apparatus already connected to the Distribution System each of which
shall be termed a “Development” in this PC;
(b) the relevant Standard Planning Data as listed in Appendix A; and
(c) the desired completion date of the proposed Development.
9.2 A User must, within 28 days after acceptance of an offer made by the DNO for a new
Connection Agreement (or such longer period as the DNO may reasonably agree in a
particular case), supply (to the extent not already supplied) to the DNO the relevant
Detailed Planning Data as listed in Appendix B.
9.3 Any User seeking to establish modified arrangements for connection to the
Distribution System must, in addition to the provisions set out above, apply to the
DNO in accordance with the procedure set out in the relevant Connection Agreement.
10 Offers Conditional on Consents and Statutory Obligations
10.1 An offer by the DNO to a User for connection to the Distribution System may be
conditional upon the obtaining of or compliance with any necessary consents,
approvals, permissions, wayleaves, or other external requirements (whether of a
statutory, contractual or other nature).
10.2 A User whose Development requires the DNO to obtain any of the consents,
approvals, permissions and wayleaves or to comply with any other requirements
referred to in paragraph 10.1 shall:-
(a) provide any necessary assistance, supporting information or evidence; and
(b) ensure attendance by such witness as the DNO may reasonably request.
10.3 If any planning or other consent or approval is granted, but is conditional upon a
change in the design arrangements originally offered by the DNO (e.g.
undergrounding), then the DNO shall make a revised offer to the User, including
revised terms and timing. This revised offer shall form the basis of any Connection
Agreement.
10.4 The Connection Agreement will deal with the consequences if any necessary consent
is not granted.
11 Annual Planning Data Requirements
11.1 Requirement to provide annual planning data
11.1.1 Users must provide sufficient planning data annually as set out below, or as
reasonably requested by the DNO from time to time, to enable the DNO to
comply with the requirements under its Licence and under the Grid Code.
11.1.2 Planning data submissions must be:-
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(a) provided by the categories of Users specified in paragraph 11.2.1 on a
routine annual basis by the end of calendar week 9 of each year or such
other annual date as the DNO may, upon not less than 6 months’ notice,
notify to such Users in writing; and
(b) provided by a User at the time that it notifies the DNO of any proposed
significant changes to its operating regime.
11.1.3 Annual planning data submissions must be in respect of the remainder of the
current year and each of the seven succeeding calendar years (other than in the
case of Registered Project Planning Data which will reflect the current
position).
11.1.4 In the case of submission on a routine annual basis, where from the date of one
annual submission to another there is no change in the data (or 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 the relevant data)
submitted the previous time.
11.1.5 In the case of submissions under paragraphs 11.1.2(b), the notification must
include the time and date at which the proposed change will become, or is
expected to become, effective. Notice must be given as soon as practicably
possible in advance to enable the DNO to implement properly any necessary
System modifications. In the event of unplanned changes in a User’s operating
regime the User shall notify the DNO as soon as is practicably possible to
ensure that any contingency measures, which the DNO considers necessary, can
be implemented by the DNO.
11.2 Data to be provided
11.2.1 Standard Planning Data in every case, and Detailed Planning Data if
required by the DNO, by reasonable notice in advance of the submission
(“reasonableness” being judged in this context by reference to the amount of
time which it may take to collate the required data), shall (unless there has been
no change from the data submitted the previous time, in which case the
provisions of paragraph 11.1.4 shall apply) be submitted to the DNO annually
by Users in the following categories:-
(a) in respect of all Generators with distribution connected Generating
Units which have an Output of 1MW and above; and
(b) Demand Customers in respect of their Connection Sites with a
Demand of 1MW and above.
11.2.2 Standard Planning Data shall be provided by Users at the time that they notify
the DNO of any significant changes to their System or operating regime.
Detailed Planning Data shall be provided by Users in these circumstances if
required by the DNO.
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Appendix A – Standard Planning Data Requirements
1 Introduction
1.1 This Appendix A specifies the Standard Planning Data to be submitted to the DNO by
Users pursuant to the Planning Code.
1.2 Data marked thus “‡“ is only required where the Registered Capacity of a Generating
Unit is 100kW or more.
2 Connection Site and User System data
2.1 General
All Users shall provide the DNO with the details as specified in paragraphs 2.2 and 2.3
relating to their User System.
2.2 User System layout
2.2.1 Single line diagrams of existing and proposed arrangements of main connections
and primary distribution systems showing equipment ratings and if available
numbering and nomenclature.
2.3 Short Circuit Infeed
(a) The maximum 3-phase short circuit current infeed into the Distribution
System.
(b) The minimum zero sequence impedance of the User System at the Connection
Point.
3 Demand data
3.1 General
3.1.1 All Users with Demand shall provide the DNO with the Demand data, both
current and forecast, as specified in paragraphs 3.2 to 3.4.
3.1.2 So that the DNO is able to estimate the diversified total Demand at various
times throughout the year each User shall provide such additional forecast
Demand data as the DNO may reasonably request (“reasonableness” being
judged in this context by reference to the level of forecast Demand data which
may be required in order to estimate the diversified total Demand at various
times throughout the year).
3.2 Demand (Active and Reactive Power) Data Requirements
(a) Forecast peak day Demand profile (Active and Reactive) and monthly peak
Demand variations net of the output profile of all Independent Generating
Plant in time marked half hours throughout the day.
(b) Type and electrical loading of equipment to be connected:-
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(i) number and size of motors;
(ii) types of drive and control arrangements; and
(iii) other large items of equipment.
(c) The sensitivity of the Demand to any variations in voltage and Frequency on
the Distribution System.
(d) The maximum harmonic content which the User would expect its Demand to
impose on the Distribution System.
(e) The average and maximum phase unbalance which the User would expect its
Demand to impose on the Distribution System.
3.3 Fluctuating Loads > 5 MVA
(a) Details of the cyclic variation of Demand (Active Power and Reactive Power).
(b) The rates of change of Demand (Active Power and Reactive Power) both
increasing and decreasing.
(c) The shortest repetitive time interval between fluctuations in Demand (Active
Power and Reactive Power).
(d) The magnitude of the largest step changes in Demand (Active Power and
Reactive Power), both increasing and decreasing.
(e) Maximum Energy demanded per half hour by the fluctuating load cycle.
(f) Steady state residual Demand (Active Power) occurring between Demand
fluctuations.
3.4 User’s abnormal Loads
3.4.1 Details should be provided on any individual Loads which have characteristics
differing from the normal typical range of Loads in the domestic, commercial
or industrial fields. In particular, details on arc furnaces, rolling mills, traction
installations etc which are liable to cause flicker problems.
4 Generating Unit and Power Station Data
4.1 General
All Generating Unit and Power Station data submitted to the DNO shall be in the
form of:-
(a) one set of Generating Unit and Power Station data where it is connected to the
Distribution System via a busbar arrangement which is not normally operated
in a split configuration; and
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(b) separate sets of Generating Unit and Power Station data where they are
connected to the Distribution System via a busbar arrangement which is, or is
expected to be, operated in a split configuration.
4.2 Power Station data requirements
(a) Point of connection to the Distribution System in terms of geographical and
electrical location and system voltage.
(b) Capacity of Power Station (being an aggregate of all Generating Units in the
Power Station) in MW sent out for Registered Capacity, Minimum
Generation (which in the case of WFPSs shall be assumed to be zero unless a
different value is notified by the User).
(c) In the case of Controllable WFPSs or Dispatchable WFPSs, a diagram that
shows for the Controllable WFPS or Dispatchable WFPS wind speed and
direction against electrical output in MW, in ‘rose’ format.
(d) Maximum auxiliary Demand (Active Power and Reactive Power).
(e) Where Generating Units form part of a User’s System, the output from these
units is to be taken into account by the User in his Demand profile submissions
to the DNO. In such cases the User must inform the DNO of the number of
such Generating Units together with their total capacity. On receipt of such
data the User may be further required, at the DNO’s discretion, to provide
details of the Generating Units together with their Energy output profile.
(f) Operating regime of Generating Units not subject to Central Dispatch (e.g.
continuous, intermittent, peak-lopping).
4.3 Generating Unit data requirements
In relation to Generating Units other than the wind turbines comprised within a
WFPS:
(a) Prime mover type;
(b) Generating Unit type;
(c) Generating Unit rating and terminal voltage (MVA & kV);
(d) Generating Unit rated power factor;
(e) Registered Capacity sent out (MW);
(f) Minimum Generation capability (MW);
(g) Reactive Power capability (both leading and lagging) at the lower voltage
terminals of the Generator Transformers, where applicable at Registered
Capacity;
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(h) Maximum auxiliary demand in MW and MVAr;
(i) Inertia constant (MWs/MVA) ‡;
(j) Short circuit ratio ‡;
(k) Direct axis transient reactance ‡;
(l) Direct axis sub-transient time constant ‡; and
(m) Generator Transformer rated MVA, positive sequence reactance, and tap
change range ‡.
In relation to the wind turbines comprised within a WFPS, such data equivalent to that listed in
paragraph 4.3 (a) to (m) as the DNO shall reasonably require and such additional data as the
DNO may reasonably require relating to the combined performance where more than one
Generating Unit is connected at the Connection Site.
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Appendix B – Detailed Planning Data Requirements
1 Introduction
1.1 This Appendix B specifies the Detailed Planning Data to be submitted to the DNO by
Users pursuant to the Planning Code, some of which by its nature is also Standard
Planning Data.
1.2 Data marked thus “‡“ is only required where the Registered Capacity of a Generating
Unit is 100kW or more.
2 Connection Site and User System data
2.1 General
2.1.1 All Users shall provide the DNO with the details as specified in paragraphs 2.2
to 2.8 relating to their Users System.
2.2 HV User System layout
Single line diagrams of existing and proposed arrangements of main connections and
primary distribution systems including:-
(a) Busbar layouts
(b) Electrical circuitry (i.e. lines, cables, transformers, switchgear etc)
(c) Phasing arrangements
(d) Earthing arrangements
(e) Switching facilities and interlocking arrangements
(f) Operating voltages
(g) Numbering and nomenclature
2.3 HV reactive compensation equipment
For all independently switched reactive compensation equipment on the User’s System
at 11kV and above, other than power factor correction equipment associated directly
with the User’s Plant and Apparatus, the following information is required:
(a) Type of equipment (e.g. 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 in terms of electrical location and
voltage.
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2.4 Short circuit infeed to the Distribution System
Each User is required to provide the total short circuit infeeds calculated in accordance
with good industry practice into the Distribution System from its User System at the
Connection Point as follows:
(a) the maximum 3-phase short circuit infeed including infeeds from any
synchronous motor or Generating Units forming part of the User’s System;
(b) the additional maximum 3-phase short circuit infeed from induction motors or
Generating Units on the User’s System; and
(c) the minimum zero sequence impedance of the User’s System.
2.5 Lumped System susceptance
Details of equivalent lumped network susceptance of the User’s System at normal
Frequency at the Connection Point. This should include any shunt reactors which are
an integrated part of a cable system and which are not normally in or out of service
independent of the cable (i.e. they are regarded as part of the cable). It should not
include:-
(a) independent reactive compensation plant on the User’s System; or
(b) any susceptance of the User’s System inherent in the Active and Reactive
Power Demand data given under subsection paragraph 3.
2.6 System data
Each User with an existing or proposed User System connected at HV shall provide
the following details relating to that HV System:-
(a) Circuit parameters (for all circuits):
Rated voltage (kV)
Operating voltage (kV)
Positive phase sequence reactance
Positive phase sequence resistance
Positive phase sequence susceptance
Zero phase sequence reactance
Zero phase sequence resistance
Zero Phase sequence susceptance
(b) Switchgear including circuit breakers, switch disconnectors and isolators on all
circuits connected to the Connection Point including those at Power Stations:
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Rated voltage (kV)
Operating voltage (kV)
Rated short-circuit breaking current,3-phase (kA)
Rated short-circuit breaking current,1-phase (kA)
Rated load-breaking current, 3-phase (kA)
Rated load-breaking current, 1-phase (kA)
Rated short-circuit making current, 3-phase (kA)
Rated short circuit making current, 1-phase (kA)
2.7 Protection data
The information essential to the DNO relates only to Protection which can trip or
intertrip or close any Connection Point circuit breaker or any circuit breaker on the
DNO System. The following information is required:-
(a) a full description of the Protection philosophy, 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 installed or to be installed on the Generating Unit, Generator
Transformer, station transformer and their associated connections;
(d) for Generating Units having (or intended to have) a circuit breaker on the
circuit leading to the Generating Unit terminals, at the same voltage, clearance
times for electrical faults within the Generating Unit zone; and
(e) the most probable fault clearance time for electrical faults on the User’s
System.
2.8 Earthing arrangements
Full details of the means of connecting the User System to earth, either temporarily or
permanently, including impedance values.
3 Demand data
3.1 General
(a) All Users with Demand shall provide the DNO with the Demand data both
current and forecast as specified in paragraphs 3.2 and 3.3.
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(b) So that the DNO is able to estimate the diversified total Demand at various
times throughout the year, each User shall provide such additional forecast
Demand data as the DNO may reasonably request.
3.2 User’s System Demand (Active and Reactive Power)
Forecast daily Demand profiles net of the output profile of all Independent
Generating Plant directly connected to the User’s System in time marked half hours
throughout the day as follows:-
(a) peak day on the User’s System;
(b) day of peak NI Demand (Active Power); and
(c) day of minimum NI Demand (Active Power).
3.3 User Demand management data
The potential reduction in Demand available from the User in MW and MVAr, the
notice required to put such reduction into effect, the maximum acceptable duration of
the reduction in hours and the permissible number of reductions per annum.
4 Generating Unit and Power Station Data
4.1 General
All Generators with Power Stations which have a Registered Capacity of 2MW and
above shall provide the DNO with the details as specified in paragraphs 4.2 to 4.6.
4.2 Auxiliary Demand
(a) The normal Generating Unit-supplied auxiliary Load is required for each
Generating Unit at rated MW output.
(b) The Power Station auxiliary Load, if any, additional to the Generating Unit –
supplied auxiliary Load, where the Power Station auxiliary Load is supplied
from the NI System, is required for each Power Station.
4.3 Generating Unit parameters
(a) Rated terminal voltage (kV)
(b) Rated MVA
(c) Rated MW
(d) Minimum Generation (MW)
(e) Short circuit ratio
(f) Direct axis synchronous reactance ‡
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(g) Direct axis transient reactance ‡
(h) Direct axis sub-transient reactance ‡
(i) Direct axis transient time constant ‡
(j) Direct axis sub-transient time constant ‡
(k) Quadrature axis synchronous reactance ‡
(l) Quadrature axis transient reactance ‡
(m) Quadrature axis sub-transient reactance ‡
(n) Quadrature axis transient time constant ‡
(o) Quadrature axis sub-transient time constant ‡
(p) Stator time constant ‡
(q) Stator resistance ‡
(r) Stator leakage reactance ‡
(s) Turbo-generator inertia constant (MWs/MVA), or, for wind turbines comprised
within a WFPS, plant inertia constant (MWs/MVA) ‡
(t) Other than for wind turbines comprised within a WFPS, rated field current ‡
(u) Other than for wind turbines comprised within a WFPS, field current (amps)
open circuit saturation curve for voltages at the Generating Unit terminals
ranged from 50% to 120% of rated value in 10% steps as derived from
appropriate manufacturers’ test certificates ‡
4.4 Parameters for Generating Unit step-up transformers
(a) Rated MVA
(b) Voltage ratio
(c) Positive sequence reactance (at max, min, & nominal tap)
(d) Positive sequence resistance (at max, min, & nominal tap)
(e) Zero phase sequence reactance
(f) Tap changer range
(g) Tap changer step size
(h) Tap changer type: on Load or off circuit
4.5 Auxiliary transformer parameters, if applicable
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(a) Rated MVA
(b) Voltage ratio
(c) Zero sequence reactance as seen from the higher voltage side
4.6 Excitation control System parameters (not for WFPSs)
(a) DC gain of excitation loop ‡
(b) Rated field voltage ‡
(c) Maximum field voltage ‡
(d) Minimum field voltage ‡
(e) Maximum rate of change of field voltage (rising) ‡
(f) Maximum rate of change of field voltage (falling) ‡
(g) Details of excitation loop described in block diagram form showing transfer
functions of individual elements ‡
(h) Dynamic characteristics of over-excitation limiter ‡
(i) Dynamic characteristics of under-excitation limiter ‡
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Connection Conditions
1 Introduction
1.1 The Connection Conditions specify the technical, design and certain operational
criteria which must be complied with by the DNO and by Users whose Plant and
Apparatus is connected to, or who are seeking a connection to, the Distribution
System.
1.2 They also set out the procedures by which the DNO shall seek to ensure compliance
with these criteria as a prerequisite to granting approval for the connection of a User’s
Plant and Apparatus.
1.3 Procedures by which the DNO and Users may conclude a Connection Agreement are
reflected in the Planning Code. Each Connection Agreement shall require Users to
comply with the terms of the Distribution Code and the DNO will not grant approval
to connect the User’s installation to the Distribution System unless and until it is
satisfied that the criteria laid down by the Connection Conditions have, subject to any
derogations issued by the Authority, been met. The DNO’s grant of approval to
connect a User’s installation to the Distribution System shall also be subject to the
provisions of paragraph 5 of Condition 30 of the Licence held by the DNO as amended
from time to time.
1.4 Some Users may also be required to comply with the Grid Code. Where this is the
case the DNO will not energise the connection prior to the TSO confirming its
agreement to the connection being energised.
2 Objectives
2.1 The Connection Conditions are designed to ensure that:-
(a) no new or modified connection will impose unacceptable effects on the
Distribution System, on any User System or on the Transmission System nor
will it be subject itself to unacceptable effects by its connection to the
Distribution System; and
(b) the basic rules for connection treat all Users of an equivalent category in a nondiscriminatory
fashion, in accordance with the DNO’s statutory and Licence
obligations.
3 Scope
3.1 The Connection Conditions apply to the DNO and to Users which, in the Connection
Conditions, means:-
(a) Generators to the extent further specified in these Connection Conditions; and
(b) Demand Customers in respect of their Connection Sites with a Demand of
1MW and above.
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3.2 Persons whose prospective activities would place them in any of the above categories of
User will, as a result of the application procedures for a Connection Agreement,
become bound by the Connection Conditions prior to their generating or consuming
electricity, 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.
4 Connection Design
4.1 The design of connections between the Distribution System and Users’ Systems shall
be in accordance with the Licence Standards where such standards are applicable.
4.2 The DNO will determine the point, including the voltage, at which each User may be
connected to the Distribution System.
5 Distribution System Electrical Parameters
5.1 General
5.1.1 The Frequency, voltage, harmonic content and phase unbalance design criteria
of the Distribution System are set out in paragraphs 5.2 to 5.5. Users should
take these factors into account in the design of Plant and Apparatus.
5.1.2 Each User shall ensure that its Plant and Apparatus connected to the
Distribution System are capable of operating under any variation in the
Distribution System Frequency and voltage as set out in paragraphs 5.2 and
5.3.
5.2 Distribution System Frequency and Frequency variations
The Frequency of the Distribution System is outwith the control of the DNO but, as
set out by the TSO in the Grid Code:
5.2.1 The Frequency is nominally 50 Hz and shall normally be within the limits of
49.5 Hz to 50.5 Hz in accordance with the Electricity Supply Regulations (N.I.)
1991.
5.2.2 In exceptional circumstances, System Frequency could rise to 52 Hz or fall to
47 Hz but sustained operation outside the range specified in the Electricity
Supply Regulations (N.I.) 1991 is not envisaged.
5.3 Voltage variations
5.3.1 The voltage variation to Demand Customers, as measured at the Connection
Point, shall comply with the Electricity Supply Regulations (N.I.) 1991, that is,
will normally remain within ± 6% of the nominal value or as otherwise agreed.
5.3.2 The design criteria in respect of voltage fluctuations shall be in accordance with
Engineering Recommendation P28.
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5.3.3 The design criteria in respect of voltage unbalance shall be in accordance with
Engineering Recommendation P29.
5.3.4 Under fault and circuit switching conditions the rated Frequency component of
voltage may fall or rise transiently. The fall and rise in voltage will be affected
by the method of Earthing of the respective system voltage neutral point.
5.3.5 Each connection to the Distribution System must not adversely affect the
method of Voltage Control employed by the DNO. Information on the voltage
regulation and control arrangements will be made available by the DNO on
request by the User.
5.4 Harmonic content
5.4.1 The design criteria in respect of harmonic distortion shall be in accordance with
Engineering Recommendation G5/4.
6 General Technical Criteria for Plant and Apparatus Connected to the Distribution
System
6.1 The User’s Plant and Apparatus shall comply with the principles outlined in
Regulation 28 of the Electricity Supply Regulations (N.I.) 1991 and Regulations 4-12
and 15 of the Electricity at Work Regulations (N.I.) 1991 or any amendments to or restatements
of those provisions.
6.2 All Users’ Plant and Apparatus which are connected to the Distribution System shall
meet the technical design and operational criteria set out in this paragraph 6. Detailed
information relating to a particular connection will, where indicated below, be made
available by the DNO on request by the User.
6.3 Plant and Apparatus
6.3.1 The DNO shall ensure in respect of its equipment, and Users shall ensure in
respect of their own equipment, that subject as provided in paragraph 6.3.2
below, the principles of design, manufacture, installation and testing of
overhead lines, underground cables and other Plant and Apparatus designed
after 31 March 1992 shall conform to (and such equipment shall comply with)
all applicable statutory obligations and the applicable requirements of the
following standards, each as current at the date of design of such Plant and
Apparatus, which shall apply (to the extent of any inconsistency) in the
following order of precedence:-
(a) relevant European Technical and Quality Assurance Standards or
European Specification;
(b) relevant IEC Publications or other international standards; and
(c) relevant British Standards or other equivalent national standard.
6.3.2 In the case of Plant or Apparatus:-
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(a) designed prior to 31 March 1992 and in use or awaiting re-use at such
date (or about to be used at such date); and
(b) designed after 31 March 1992 and subsequently re-used;
the applicable standards under paragraph 6.3.1 above shall be those which were
current at the date when the Plant or Apparatus was originally designed,
provided that the DNO reasonably considers the Plant and/or Apparatus to be
fit for its purpose having full regard to the respective obligations of the DNO
and the relevant User, and otherwise shall be those current at the date of re-use.
6.4 The short circuit rating and insulation level of a User’s Apparatus at the relevant
Connection Point shall not be less than that specified in the relevant Connection
Agreement.
6.5 Each of the DNO and a User shall ensure that the specification of their respective Plant
and Apparatus at the Connection Site shall be such as to permit operation within the
applicable Local Safety Instructions.
6.6 Metering
6.6.1 The requirements to be met by each User in respect of metering equipment are
set out in the Distribution Metering Code.
6.7 Protection
6.7.1 All User Systems and the Distribution System must incorporate Protection in
accordance with the requirements of the Electricity Supply Regulations (N.I.)
1991 as amended or re-stated.
6.7.2 The basic requirement in all cases is that Users’ arrangements for Protection at
the Connection Point, including types of equipment and Protection settings
must be compatible with standard practices on the Distribution System from
time to time, whilst maintaining necessary discrimination and co-ordination.
Relevant details of the application of these requirements to a particular
connection will be made available to the User upon request pursuant to
paragraph 6.2.
In particular:-
(a) maximum fault clearance times (from fault inception to arc extinction)
must be within the limits established by the DNO in accordance with the
Protection and equipment short circuit rating policy adopted by the
DNO from time to time for the Distribution System;
(b) auto reclosing or sequential switching features may be in use on the
Distribution System. The DNO will on request provide details of the
auto-reclose or sequential switching features;
(c) the Protection arrangements on some parts of the Distribution System
may cause disconnection of, or low voltages on, one or more phases
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only of a three phase supply for certain types of fault. Users should
make provision to safeguard their equipment from the effects of such
events; and
(d) in the case of a three phase and neutral supply system, a fault
disconnecting the neutral can lead to higher than normal voltage
appearing on one or more phases.
6.8 During the course of an application for a Connection Agreement the DNO shall
specify the Protection standards applicable to the Distribution System and agree with
the User (or, in the event that agreement cannot be reached, the DNO will determine
acting reasonably) any conditions for compatibility with the DNO’s Protection
arrangements which shall be complied with by the User.
In particular:-
(a) in order to ensure satisfactory operation of the Distribution System, Protection
systems, operating times, discrimination and sensitivity at the Connection Point
shall be agreed between the DNO and the User (or, in the event that agreement
cannot be reached, shall be determined by the DNO) and may be reviewed from
time to time by the DNO. If, as a consequence of such review, the DNO
identifies a requirement for some variation to such Protection arrangements, the
relevant provisions of the Connection Agreement shall apply;
(b) in order to cover a circuit breaker or equipment having a similar function failing
to operate correctly to interrupt fault current on a High Voltage System, backup
Protection by operation of other circuit breakers or equipment having a
similar function must normally be provided by the User. The DNO will inform
the User if it is not required. If the back-up circuit breaker is owned by the
DNO, it may be equipped with Protection that is limited to that required to
provide excess Energy Protection to the Distribution System; and
(c) unless the DNO specifies otherwise, it is not acceptable for Users to limit the
fault current infeed to the Distribution System by the use of Protection and
associated equipment if the failure of the Protection and associated equipment
to operate as intended in the occurrence of a fault could cause equipment owned
by the DNO to operate outside its short-circuit rating.
Certain provisions on working on certain Protection equipment are included in
paragraph 9.
6.9 Intertripping
6.9.1 In all circumstances where the isolation of faults or System abnormalities is
dependent upon the operation of both the DNO’s and the User’s circuit
breakers, Intertripping facilities may be required. These Intertripping
facilities shall be in accordance with the requirements of the relevant
Connection Agreement.
6.10 Automatic reclosure
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6.10.1 Where automatic reclosure of the DNO circuit breaker is required following
faults on a User’s System, automatic switching equipment shall be provided in
accordance with the requirements of the relevant Connection Agreement.
6.11 Voltage fluctuations and unbalance and harmonic distortion
6.11.1 The design criteria to be applied to Users’ Loads connected to the Distribution
System to limit voltage fluctuations and unbalance and harmonic distortion will
be notified to the User in the course of an application for connection to the
Distribution System and will be in accordance with the Licence Standards,
which are listed in Appendix 3 to these Connection Conditions. In the event
that a User causes any such limits to be breached, the DNO shall be entitled to
require the User to take such steps as the DNO reasonably considers to be
necessary in order to prevent such breach from continuing and the User shall
comply with the DNO’s instructions without delay.
6.12 Neutral Earthing
6.12.1 The specification of a User’s Apparatus shall meet the voltages which will be
imposed on the Apparatus as a result of the method of Earthing of the
Distribution System as specified in the relevant Connection Agreement.
6.12.2 The Earthing of a User’s Apparatus at the Connection Point must be in
accordance with current DNO practice which will be notified to the User,
initially, during the course of an application for connection to the Distribution
System. In the event that the DNO wishes to change its current practice, the
DNO will notify the User as soon as reasonably practicable in advance of the
change and any modifications which such change will require to be undertaken
on the User’s System will be implemented in accordance with the modifications
procedure set down in the User’s Connection Agreement, if it is applicable.
6.12.3 Users shall take all reasonable precautions in relation to a particular Connection
Point to limit the occurrence and effects of circulatory currents in respect of
neutral points of any interconnected system (e.g. where there is more than one
source of Energy).
6.13 Superimposed signals
6.13.1 Where a User proposes to use mains borne signalling equipment to superimpose
signals on the Distribution System, the prior written agreement of the DNO is
required (which agreement will not be unreasonably withheld).
7 Additional Technical Criteria for Generating Units
7.1 All Generating Units shall, in addition to the requirements of paragraph 6, meet the
technical design and operational criteria in this paragraph 7, insofar as each
requirement is applicable to them, which contains more detailed requirements for
Generating Units than those set out in paragraph 6 and is intended to be
complementary to paragraph 6. However, in the event of any conflict between the
requirements of paragraph 6 and the requirements of this paragraph 7, the provisions of
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this paragraph 7 shall prevail. Detailed information relating to a particular connection
will, where indicated below, be made available by the DNO on request by the
Generator.
7.2 Each connection between a Generating Unit and the Distribution System, unless
specified otherwise in the Connection Agreement, must be controlled by a circuit
breaker capable of interrupting the maximum short circuit current at the Connection
Point. The short circuit current design values at a Connection Point will be set out in
the Connection Agreement.
7.3 All Generating Units must comply with the requirements of NIE Engineering
Recommendation G59/1/NI, Recommendations for the connection of embedded
generating plant to Public distribution systems above 20kV G75/1 or with outputs over
5MW, and Engineering Recommendation G83/1, each as applicable and as amended,
supplemented, varied or replaced from time to time and with all other relevant
Engineering Recommendations and relevant regulations and the particular requirements
of the DNO which will take account of the conditions prevailing on the Distribution
System at the Connection Point at the relevant time. The DNO will notify its
particular requirements to the Generator during the course of the Generator’s
application for connection to the Distribution System.
7.4 Reactive Power capability
7.4.1 Each Generating Unit must be capable of operating at its Registered Capacity
in a stable manner within the following power factor ranges:
Range
Type A Generating Units 0.95 absorbing – 0.98 absorbing
Type B Generating Units 0.95 absorbing – 0.98 generating
7.4.2 In this paragraph 7 Type A Generating Units means Induction Generating
Units.
7.4.3 In this paragraph 7 Type B Generating Units means:
(a) Synchronous Generating Units;
(b) Generating Units of all types connected in part or in total through
convertor technology with a Registered Capacity of 100kW and above;
and
(c) Generating Units within a WFPS with a Registered Capacity of 5MW
and above.
7.4.4 Each Generating Unit with a Registered Capacity of 100kW or more shall
have a minimum Reactive Power capability at its Registered Capacity as
described in the following diagrams:-
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Connection Conditions Page 33
Voltage
Generating
MVAr at
rated MW
Absorbing
MVAr at
rated MW
90% 95% 100% 105%
1.0
0.95
0.95
0.98
94% 106% 110%
0.98
Power
Factor
Type A Generating Units
Voltage
Generating
MVAr at
rated MW
Absorbing
MVAr at
rated MW
90% 95% 100% 105%
1.0
0.95
0.95
0.98
94% 106% 110%
0.98
Power
Factor
Type B Generating Units
7.4.5 The short circuit ratio for each Generating Unit shall not be less than 0.5.
7.4.6 For the avoidance of doubt, all Generating Units must be capable of delivering
the power factor performance at the Connection Point. However, where
complex User Systems involve Generating Units and Load, the User may
submit calculations to support compliance.
7.5 Co-ordination with existing Protection
7.5.1 Each Generator must meet, in relation to each of its Generating Units, the
target clearance times for fault current interchange with the Distribution
System in order to reduce to a minimum the impact on the Distribution System
of faults on circuits owned by a Generator. The target clearance times are
measured from fault current inception to arc extinction and will be specified by
the DNO to meet the requirements of the relevant part of the Distribution
System. A Generator may obtain relevant details specific to its Generating
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Units pursuant to paragraph 6.2. The DNO shall ensure that (subject to any
necessary discrimination) the same target fault clearance times can be achieved
by its own Apparatus at each Connection Point.
7.5.2 Unless otherwise agreed, the fault clearance times required by the Connection
Agreement shall not be faster than 120 ms but, if otherwise agreed, nothing in
this paragraph 7.5.2 shall prevent a Generating Unit or the DNO’s Apparatus
at the Connection Point from having faster clearance times (subject to
necessary discrimination being maintained). The times specified in the
Connection Agreement will reflect the DNO’s view of the requirements of the
Distribution System, and the User’s System, for the expected life time of the
Protection (for example, 15 years). The probability that the fault clearance
times stated in the Connection Agreement will be exceeded by any given fault
must be less than 2%.
7.5.3 To cover for failure of the above Protection systems to meet the above fault
clearance times, the Generator may be required to provide back up Protection.
The back up Protection shall be required to discriminate with other Protections
fitted on the Distribution System. Relevant details will be made available to a
Generator upon request pursuant to paragraph 7.1.
7.5.4 The setting of any Protection controlling a circuit breaker or the operating
values of any automatic switching device at any Connection Point shall have
been agreed between the DNO and the User during the course of the application
for a Connection Agreement. The settings and operating values will only be
changed if both the DNO and the User agree provided that neither the DNO nor
the User shall unreasonably withhold their consent.
7.5.5 If in the opinion of the DNO following an overall review of Distribution
System Protection requirements improvements to any Generating Unit
Protection scheme are necessary, the relevant provisions of the Connection
Agreement shall be followed.
7.5.6 The Generating Unit Protection must co-ordinate with any auto reclose policy
specified by the DNO.
7.6 Minimum connected impedance
7.6.1 For Generating Units which do not form part of a WFPS the minimum
connected impedance applicable to the generator and Generator Transformer
will be specified in the Connection Agreement. The DNO’s requirements for
the impedances will reflect the needs of the Distribution System from the fault
level and stability points of view.
7.6.2 For WFPSs the minimum connected impedance applicable to the whole WFPS
as a single unit will be specified in the Connection Agreement. The DNO’s
requirements for the impedance will reflect the needs of the Distribution
System from the fault level and stability points of view.
7.7 Variations in System Frequency
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7.7.1 In order to comply with its Grid Code obligations, the DNO requires that, apart
from those circumstances set out in sub-paragraph 7.7.2, all Independent
Generating Plant with an Output of 100kW or more shall stay connected and
operate:
(a) continuously where the Distribution System Frequency varies within
the range 49.5 to 52.0 Hz;
(b) for a period of up to one hour where the Distribution System
Frequency varies within the range 48.0 to 49.5 Hz; and
(c) for a period of up to 5 minutes where the Distribution System
Frequency varies within the range 47.0 to 48.0 Hz.
7.7.2 The requirements of paragraph 7.7.1 do not apply where:
(a) the G59 relay has operated correctly, consistent with the settings agreed
pursuant to paragraph 7.8; or
(b) The Distribution System Frequency has changed at a rate greater than
0.5 Hz/s; or
(c) there is manual intervention by the Generator.
7.8 Agreement of rate-of-change-of-frequency settings
7.8.1 Where Generating Units are equipped with rate-of-change-of-frequency relays
or other devices which measure and operate in relation to a rate-of-change-of
frequency the procedure in paragraphs 7.8.2 to 7.8.5 below will be followed to
ensure satisfactory operation of the Generating Unit.
7.8.2 At a reasonable time prior to a Generating Unit being connected to the
Distribution System, and prior to any relevant modification to a Generating
Unit or any relevant Power Station Equipment, the Generator shall contact
the DNO with details of the proposed rate-of-change-of-frequency setting.
7.8.3 The DNO shall, within a reasonable period and in any case no more than 28
days after being contacted pursuant to paragraph 7.8.2, discuss with the
Generator whether the proposed settings are satisfactory. The agreed settings
shall be specified in the Connection Agreement.
7.8.4 In relation to any Generator which has agreed the settings with the DNO under
these provisions, the DNO shall notify that Generator of any change of which it
is aware in the expected rate-of-change-of-frequency on the Distribution
System which may require new settings to be agreed.
7.8.5 Each Generator shall be responsible for protecting the Generating Unit owned
or operated by it against the risk of damage which might result from any
Frequency excursion outside the range 52 Hz to 47 Hz and for deciding
whether or not to interrupt the connection between its Plant and/or Apparatus
and the Distribution System in the event of such a Frequency excursion.
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7.9 Generating Unit control arrangements
7.9.1 All Generating Units in use after 1 January 2010 must be fitted with a device
capable of setting the power factor of the Generating Unit within the relevant
range, as set out in paragraph 7.4.
7.9.2 All Generating Units first connected on or after 1 January 2010 with an
Output of 100kW or more, all WFPSs with an Output of 5MW or more first
connected on or after 1 November 2007 and all Generating Units with an
Output of 10 MW or more (other than WFPSs) connected to the Distribution
System since 31 March 1992, must be fitted with a fast acting control system
capable of being switched between Voltage Control mode and power factor
control mode within a voltage band as specified within the Connection
Agreement for the particular site, and in any case within statutory limits as
specified under paragraph 5.3. If the voltage is outside the specified limit the
power factor control must revert to Voltage Control. The control of voltage and
power factor must ensure stable operation over the entire operating range of the
Generating Unit. In the event that action by the Generating Unit Active and
Reactive Power control functions is unable to achieve a sustained voltage within
the statutory limits, the Generating Unit must detect this and immediately shut
down.
7.9.3 Where a WFPS is connected to the Distribution System through the same
transformer as a Demand Customer or Demand Customers, the Generator
may be required to install a power factor control loop as further provided in the
Connection Agreement. The power factor control loop should be designed to
be slow acting to allow the Voltage Control loop to respond to transient voltage
changes. Where a transient voltage change occurs, the power factor control loop
must restore the voltage to the set value over a period of 1 minute.
7.9.4 Other Voltage Control schemes may be possible, but agreement between the
Generator and the DNO must be reached at the application stage for connection
about their suitability. If Voltage Control is implemented for the Controllable
WFPS or Dispatchable WFPS, rather than on individual wind turbines, then
the range of power factor available should not be less than that which would
have been available if Voltage Control had been on individual wind turbines.
Voltage Control schemes based upon equipment located on the DNO’s side of
the connection may be possible, but such schemes are considered special, and
the details, responsibilities and cost schedule must be agreed between the
Generator and the DNO in the Connection Agreement.
7.10 Generating Unit SCADA and control
7.10.1 Generators shall in respect of their Generating Units in any of the following
three categories comply with the SCADA signal requirements set out in this
paragraph 7.10 and, in addition, such other SCADA signal requirements as the
DNO may require because of network reasons, which will be specified prior to
entry into the Connection Agreement:
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(a) Generating Units with an Output of 1MW or more which are first
connected after 1 January 2010;
(b) Generating Units with an Output of 100kW or more up to 1MW which
are first connected after 1 January 2010 where the DNO decides that
SCADA is required because of local network reasons; and
(c) Generating Units with an Output of 5MW or more which were
connected prior to 1 January 2010.
7.10.2 The DNO shall issue control instructions by means of the SCADA signals set
out below or, in the event of a SCADA malfunction, such other means as are
determined by the DNO in consultation with the User.
7.10.3 The User shall acknowledge, where relevant, receipt of a control instruction
issued under this paragraph 7.10 and shall comply promptly with the control
instruction.
7.10.4 The following signal formats shall be used where required by the particular
connection:
(a) Analogue signals: 4 to 20 mA
(b) Digital pulse from the DNO: 24V dc
(c) Digital input from the User: 0 and 24V dc
7.10.5 Analogue signals:
Ref Quantity Comment From To
1 Voltage Voltage set point instruction DNO User
2 Voltage Confirmation of voltage set point User DNO
3 Set Point Power factor set point instruction DNO User
4 Set Point
Confirmation of power factor set point
instruction
User DNO
7.10.6 Digital signals:
Ref Quantity Comment From To
1
Voltage Control
Select
To operate in Voltage Control mode DNO User
2
Voltage Control
Selected
Acknowledgement signal that the
Generating Unit is in Voltage Control
mode.
User DNO
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Ref Quantity Comment From To
3 PF Control Select
To operate in power factor control
mode
DNO User
4 PF Control Selected
Acknowledgement signal that the
Generating Unit is in power factor
control mode.
User DNO
5
Voltage Control
Auto Change Over
Indication that the control mode has
changed to Voltage Control.
User DNO
6 Island Detected Trip
Indication that the G59 protection has
operated.
User DNO
7.10.7 Analogue signals applicable to WFPSs with Registered Capacities of less than
5MW and greater than or equal to 1MW:
Ref Quantity Comment From To
1 Wind Speed
Indication of wind speed at WFPS, measured
at a location agreed between the generator
and the DNO.
User DNO
2 Wind Direction
Indication of wind direction at WFPS,
measured at a location agreed between the
generator and the DNO.
User DNO
7.11 Neutral Earthing
7.11.1 The winding configuration and method of Earthing of Generating Units and
associated Generator Transformers shall be agreed with the DNO or, if
agreement cannot be reached, determined by the DNO.
8 Technical Criteria for Communications
8.1 Communications equipment
8.1.1 Where required by the DNO in order to ensure control of the Distribution
System, communications between Users and the DNO shall be established in
accordance with the relevant Connection Agreement.
8.2 Telemetry
8.2.1 In addition to the requirements of the Distribution Metering Code, each User
shall provide such voltage, current, Frequency, Active and Reactive Power
measurements and status points and alarms and controls at the DNO telemetry
outstation interface (if any) as required and specified by the DNO in the relevant
Connection Agreement.
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8.2.2 If it is agreed between the DNO and a User that the DNO will telecontrol the
User’s switchgear on the User’s Site, the DNO shall install the necessary
telecontrol facilities. It shall be the responsibility of the User to provide the
necessary control interface for the switchgear of the User which is to be
controlled.
8.3 Telecontrol connection standards
8.3.1 All communication connections between each User and the DNO shall conform
to:
(a) appropriate Telecommunication Standardization Sector (ITU-T)
standards and other standards required by licensed public telephone
operators; and/or
(b) appropriate standards for radio systems as required by Ofcom from time
to time.
8.3.2 In respect of (b) above, each User shall, except to the extent that an alternative
means of communication has been agreed with the DNO in a Connection
Agreement, provide where required by the DNO, as set out in the DNO’s
connection offer, facilities on which a small radio aerial can be mounted and
shall obtain where necessary any planning permissions required therefor.
9 Site Related Conditions
9.1 Ownership, control, operation & maintenance at the Connection Point
9.1.1 The ownership boundary between the Distribution System and a User’s System
shall be agreed between the User and the DNO. For supplies at Low Voltage
the general rule is that the ownership boundary will be at the User’s terminals of
the DNO owned metering equipment. For High Voltage supplies and busbar
connected supplies at Low Voltage, the ownership boundary will be subject to
specific agreement between the DNO and the User in each case.
9.1.2 In the absence of a separate written agreement between the parties to the
contrary, construction, commissioning, control, operation and maintenance
responsibilities follow ownership.
9.1.3 For connections to the Distribution System for which a Connection
Agreement is required and those covered by regulation 26 and parts 1 and 2 of
schedule 3 of the Electricity Supply Regulations (N.I.) 1991, as amended or restated
from time to time, a Site Responsibility Schedule shall be prepared by
the DNO (reflecting the details agreed between the DNO and the User) in
respect of each Connection Site pursuant to the relevant Connection
Agreement and signed by both parties (by way of confirmation of its accuracy),
detailing the division of responsibilities at interface sites in respect of
ownership, control, operation, maintenance and safety. The format, principles
and basic procedure to be used in the preparation of Site Responsibility
Schedules are set down in Appendix 1.
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9.1.4 An Ownership Diagram shall be included in the above Site Responsibility
Schedule. The diagram shall show all HV Apparatus and the connections to all
external circuits and shall incorporate numbering, nomenclature and labelling as
set out in OC9. A guide to the types of HV Apparatus to be shown in the
Ownership Diagram is shown in Appendix 2 together with the principles to be
followed in the preparation of the diagram and the preferred graphical symbols
to be used.
9.1.5 A copy of the Site Responsibility Schedule and any Ownership Diagrams
shall be retained by the DNO and by the User.
9.1.6 The User shall notify the DNO of any changes at or relating to the Connection
Site which may affect the Site Responsibility Schedule or Ownership
Diagrams and the DNO shall carry out any necessary updating and the
principles set out in paragraph 9.1.3 shall apply to such updating.
9.2 Access to Sites
The provisions relating to access to DNO Sites by Users and to User’s Sites by
members or representatives of the DNO shall be set out in the relevant Connection
Agreement and/or lease.
9.3 Work on Protection at Connection Points
No busbar Protection, mesh corner Protection, circuit breaker fail Protection, AC or
DC wiring (other than power supplies or DC tripping associated with a Generating
Unit) at a Connection Point shall be worked upon or altered by or on behalf of a User
unless the DNO has been given a reasonable opportunity to arrange for a DNO
representative to attend. The DNO shall not work upon or alter any Generating Unit
Protection unless it has given the Generator a reasonable opportunity for a
representative of the Generator to attend.
9.4 Standard of maintenance
9.4.1 It is a requirement that all User’s Plant and Apparatus on DNO Sites is
maintained adequately for the purpose for which it is intended and to ensure that
it does not pose a threat to the safety of any of DNO’s Plant, Apparatus or
personnel on the DNO Site.
9.4.2 The DNO shall ensure that all of the Distribution System Plant and Apparatus
on Users’ Sites is maintained adequately for the purpose for which it is intended
and to ensure that it does not pose a threat to the safety of any User’s Plant,
Apparatus or personnel on the User’s Site.
9.4.3 The DNO or the User (as the case may be) will have the right to inspect the test
results and maintenance records relating to such Plant and Apparatus at any
time.
9.5 Responsibility for safety
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9.5.1 The Site Responsibility Schedule referred to in paragraph 9.1.3 shall detail the
demarcation of responsibility for safety of persons carrying out work or testing
at Connection Sites and on circuits which cross a Connection Site at any point.
9.5.2 More detailed information on procedures and responsibilities involved in the
provision of Safety Precautions is set out in OC6.
10 Approval To Connect
10.1 Readiness to connect
10.1.1 A User whose development is under construction in accordance with the
relevant Connection Agreement and who wishes to establish a connection, or to
modify an existing connection, to the Distribution System shall apply to the
DNO by submitting a standard connection card or otherwise in writing, stating
readiness to connect and giving the following:-
(a) confirmation that the User’s installation complies with the principles
outlined in Regulation 28 of the Electricity Supply Regulations (N.I.)
1991 and Regulations 4-12 and 15 of the Electricity at Work Regulations
(N.I.) 1991 (or as amended or re-stated);
(b) where relevant, updated Planning Code data based on actual values; and
(c) a proposed connection date.
10.1.2 The DNO may require a User to provide in addition to its written application to
the DNO for connection in accordance with paragraph 10.1.1, a report,
prepared by such person as the DNO may reasonably consider to be competent
to issue the same, certifying to the DNO that all matters required by paragraph
5 have been considered and that paragraphs 6 to 8 inclusive have been complied
with by the User and incorporating:-
(a) all available type test reports and test certificates produced by Nationally
Accredited Laboratories (or other equivalent testing organisations)
showing that the Plant and Apparatus specified in the Connection
Conditions meets the criteria specified;
(b) copies of the manufacturer’s test certificates relating to Plant and
Apparatus referred to in the Connection Conditions, including
measurements of positive and zero sequence impedance of Apparatus
which will contribute to the fault current at the Connection Point;
(c) details of Protection arrangements and settings;
(d) a certificate declaring the maximum short circuit current in amperes
which the User’s System would contribute to a three-phase short circuit
at the Connection Point, and the minimum zero sequence impedance of
the User’s System at the Connection Point and taking into account the
contributions of any Generating Unit or Power Station motors and
transformers; and
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(e) confirmation that designs conform to the standards referred to in
paragraph 6.
10.1.3 A User shall supply the following information to the DNO together with its
notification under paragraph 10.1.1:-
(a) a list of persons proposed to be appointed by the User to undertake, and
to be responsible for, the application and removal of Safety Precautions
on those parts of the User’s System which are directly connected to the
Distribution System, in accordance with OC6;
(b) a list of persons appointed by the User to undertake operational duties on
the User’s System and to issue and receive operational messages and
instructions in relation to the User’s System;
(c) a list of names and telephone numbers of responsible management
representatives in accordance with OC7;
(d) site common drawings as specified in the Connection Agreement;
(e) a single line diagram of the User’s Apparatus showing all items to
which these Connection Conditions apply; and
(f) information to enable the DNO to prepare a Site Responsibility
Schedule.
10.1.4 In order that the DNO may verify that the requirements of these Connection
Conditions can be met, the User shall provide a proposed commissioning
programme, giving at least six weeks (or such longer period as the DNO may
reasonably consider to be appropriate in the circumstances) notice of the
proposed connection date, and detailing all proposed site testing of main and
ancillary equipment, together with the names of the organisations which are to
carry out such testing and the proposed timetable for such testing. The required
period of notice will be notified to the User by the DNO during the course of an
application for connection. The DNO will consider the proposed commissioning
programme and, as soon as reasonably practicable, will notify the User:-
(a) that it approves the programme, in which case the DNO and the User
shall take all reasonable steps to ensure that the
Commissioning/Acceptance Testing is undertaken in accordance with
the commissioning programme (subject to Distribution System
conditions); or
(b) that it considers that the Commissioning/Acceptance Testing proposed
in the programme may involve the application of irregular, unusual or
extreme conditions and which may have a material effect on the
Distribution System, beyond the User’s System and that such testing
therefore falls within the scope of OC10, “System Tests”, in which
event the proposed commissioning programme shall be treated as a
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Proposal Notice submitted under paragraph 4.1 of OC10 and the
relevant provisions of OC10 shall apply to the proposed testing; or
(c) that it requires the proposed commissioning programme to be amended
in which event the User and the DNO shall endeavour to agree an
appropriate amendment to the commissioning programme, failing which
the programme will be as determined by the DNO acting reasonably and,
in either case, the DNO and the User shall take all reasonable steps to
ensure that the Commissioning/Acceptance Testing is undertaken in
accordance with the commissioning programme as amended; or
(d) that it rejects the proposed commissioning programme and the reasons
for such rejection in which event, subject to the resolution of any dispute
in accordance with the relevant Connection Agreement, the proposed
Commissioning/Acceptance Testing shall not take place but the User
shall be entitled to submit a revised commissioning programme for the
DNO’s consideration.
10.1.5 The DNO shall be entitled to witness site testing of equipment whose
performance can reasonably be regarded as affecting the integrity of the
Distribution System. The User shall provide the DNO with certified results of
all such tests and the DNO may withhold agreement to energise the User’s
Equipment where test results establish that the Connection Conditions have
not been complied with.
10.1.6 Where in advance of the proposed connection date, a Generator requires
connection to the Distribution System for the purpose of testing, the Generator
will be required to satisfy the DNO of the following:-
(a) compliance with those requirements of the Connection Conditions and
Connection Agreement necessary to give assurance that it is safe to
connect; and
(b) where applicable, provision of a commissioning programme in
accordance with paragraph 10.1.4.
10.2 Confirmation of approval to connect
10.2.1 Within 30 days of notification by a User pursuant to paragraph 10.1.1 the DNO
shall (except where it has rejected the User’s application in accordance with
paragraph 10.1.4(d)) inform the User whether or not the requirements of
paragraph 10.1 and the other requirements of the Connection Conditions are
satisfied and the making of the connection is approved subject to satisfactory
results of those tests (including Commissioning/Acceptance Tests) which
cannot be performed prior to energisation of the User’s Plant and Apparatus.
Where approval is withheld, reasons shall be stated by the DNO.
10.2.2 Where the notification given by the DNO pursuant to paragraph 10.2.1 is in the
affirmative, the DNO will in addition supply to the User the following
information:-
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(a) a list of persons appointed by the DNO to undertake, and to be
responsible for, the application and removal of Safety Precautions in
relation to the Connection Site, in accordance with OC6;
(b) a list of persons appointed by the DNO to undertake operational duties
on the Distribution System and to issue and receive operational
messages and instructions in relation to the User’s System; and
(c) list of names and telephone numbers of responsible management
representatives in accordance with OC7.
10.2.3 When indicating agreement to the energising of a connection, the DNO shall, to
the extent not previously determined in a commissioning programme, specify
the contents and sequence of the energising programme and associated testing.
In either case, the DNO shall be entitled to postpone or suspend the programme
where, due to circumstances which could not reasonably have been foreseen by
the DNO, continuation of the programme would impose an unacceptable level of
risk to the integrity of the Distribution System.
10.3 Approval of staff
10.3.1 At the same time that the User submits to the DNO in relation to safety
requirements the list of information pursuant to paragraph 10.1.3, it shall submit
to the DNO a list of staff which will be used to implement Safety Precautions.
The DNO may ask the User questions to clarify the suitability of persons named
on the list.
10.3.2 At the same time that the DNO submits to the User the list of information
pursuant to paragraph 10.2.2 it shall submit to the User a list of DNO staff
which will be used to implement Safety Precautions. The User may ask the
DNO questions to clarify the suitability of persons named on the list.
10.3.3 The DNO and each User have the right to object to the inclusion of particular
members of staff on the other’s list, on technical grounds, and in the event of
objection which is accepted by the other, that member of staff will not be used
to implement Safety Precautions.
10.3.4 A party must accept an objection to the extent it is reasonable to do so. In the
event of a disagreement, the disputes resolution procedure in the relevant
Connection Agreement will be used.
10.3.5 As part of the approval process, each party may (upon reasonable notice and at
reasonable times) interview members of staff on the other’s list or the parties
may agree to hold joint interviews.
10.3.6 If the list of the DNO or a User, as the case may be, changes, the relevant party
must notify the other without delay and the relevant provisions of this paragraph
10.3 shall apply to any new names included as part of that change.
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10.3.7 Neither the DNO nor any User shall have any liability to the other by reason of
or arising from their approval under this paragraph 10.3 of the other’s list of
staff entitled to implement Safety Precautions.
11 Connection Conditions compliance testing
11.1 The DNO will specify to each User the testing to be undertaken to demonstrate
compliance with the Connection Conditions in relation to a particular connection. The
specification and the timing of the test will be consistent with the overall requirements,
including timing of the Connection Agreement. The following sets out the
requirements for testing for Generators and Demand Customers.
11.2 Generator Testing
11.2.1 The testing will be undertaken in three phases:
(a) Phase 1 – Pre-energisation
(b) Phase 2 – Post-energisation
(c) Phase 3 – Post-energisation monitoring.
11.3 Phase 1 – Pre-energisation
11.3.1 The testing in Phase 1 will require the Generator to demonstrate, in the
presence of a representative of the DNO, compliance with requirements
specified by the DNO as being the relevant parts of the Connection Conditions
against which compliance needs to be demonstrated.
11.3.2 A Pre-energisation Connection Report shall be completed by the Generator to
the satisfaction of the DNO, demonstrating compliance, which will include such
information as the DNO may reasonably specify.
11.4 Phase 2 – Post-energisation
11.4.1 Phase 2 covers certain tests which require to be witnessed by a representative of
the DNO within six months (or such other period may reasonably be specified
by the DNO) of energisation. The tests will be specified by the DNO, and will
be based on the individual test descriptions as set out in the Connection
Agreement, and such further tests as the DNO may reasonably specify to
demonstrate compliance with the Connection Conditions.
11.4.2 The tests in Phase 2 will be based on an on-site demonstration of the operation
of the Power Station. Any test which relies upon some level of generation may
be replaced with either a simulated power output signal or be demonstrated
through the analysis of individual turbine event logs to confirm receipt of the
appropriate control signal, in each case subject to the reasonable agreement of
the DNO to such alternative approach.
11.4.3 In the event that conditions (relating to wind or the conditions on the network
generally) do not allow the test to be performed, then a demonstration of the
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control functionality would normally be sufficient to demonstrate compliance
with Phase 2, subject to the agreement of the DNO. The DNO may agree that
any physical tests were not completed as part of the Phase 2 witness tests will be
included in the Phase 3 monitoring phase.
11.5 Phase 3 – Post-energisation Monitoring
11.5.1 The operation of the Power Station over a range of conditions will be
confirmed by operational monitoring in Phase 3. During the twelve month
period after energisation, a number of operations, as specified by the DNO, will
be required. The results of monitoring the performance of those operations will
be included in the Final Connection Report. The operational monitoring period
of Phase 3 will be required to confirm to the DNO’s reasonable satisfaction the
Power Station’s and its individual Plant and/or Apparatus’ behaviour and
capability under various conditions and subject to disturbances, which generally
cannot be simulated during the commissioning tests. The undertaking of the
operational monitoring will require the installation of an event recorder or
similar device by the DNO at or near to the Connection Point.
11.5.2 If the relevant conditions necessary to complete the Phase 3 are not experienced
during the twelve months following energisation, then nevertheless the final
compliance certificate will be issued by the DNO at the expiration of that twelve
month period.
11.6 Demand Customer Testing
In the case of Demand Customers a Pre-energisation Connection Report will be
completed by the User to the satisfaction of the DNO, which includes such information
as may be reasonably specified by the DNO to demonstrate compliance with the
Connection Conditions and any other relevant part of the Distribution Code.
12 Fuel Security Code
Each Generator agrees to comply with the Fuel Security Code to the extent that it is
expressed to apply to it and with any instructions from the DNO or the TSO pursuant
to the Fuel Security Code.
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APPENDIX 1
FORMAT, PRINCIPLES AND BASIC PROCEDURE TO BE USED IN THE PREPARATION OF SITE
RESPONSIBILITY SCHEDULES
1 Principles
1.1 Site Responsibility Schedules shall be drawn up covering the following:
(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 and Power Station locations (including WFPSs), the
schedules referred to in (b) and (c) may be combined.
1.2 Each Site Responsibility Schedule for a Connection Site shall be prepared by the
DNO in consultation with other Users at least 2 weeks prior to the date for connection
proposed by the User pursuant to paragraph 10.1.1(c) in the Connection Conditions.
Each User shall provide information to the DNO to enable it to prepare the Site
Responsibility Schedule.
1.3 Each Site Responsibility Schedule shall detail for each item of Plant and Apparatus:-
(a) Plant/Apparatus ownership;
(b) Site Manager;
(c) Safety (applicable Safety Rules and Control Person or other responsible person
(Safety Co-ordinator), or such other person who is responsible for safety);
(d) Operations (applicable Operational Procedures and control engineer);
(e) Responsibility to undertake maintenance.
Each Connection Point shall be precisely shown.
1.4 In the case of Site Responsibility Schedules referred to in paragraph 1.1 (b) and (c),
with the exception of Protection and Intertrip Apparatus operation, it will be
sufficient to indicate the responsible User or the DNO as the case may be. In the case
of the Site Responsibility Schedule referred to in 1.1 (a) for Protection and Intertrip
Apparatus, the responsible management unit must be shown in addition to the User or
the DNO as the case may be.
1.5 The HV Apparatus Site Responsibility Schedule for each Connection Site must
include lines and cables emanating from the Connection Site.
1.6 Every page of each Site Responsibility Schedule shall bear the date of issue and the
issue number.
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Connection Conditions Page 48
1.7 When a Site Responsibility Schedule is prepared it shall be sent by the DNO to the
Users involved for confirmation of its accuracy
1.8 The Site Responsibility Schedule shall then be signed on behalf of the DNO by the
Manager responsible and on behalf of each User involved by its Responsible Manager
(see paragraph 3.1), by way of written confirmation of its accuracy if they agree on its
accuracy.
1.9 Once signed, two copies will be distributed by the DNO, 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.
1.10 The DNO and Users must make the Site Responsibility Schedules readily available to
their respective operational staff at the Site.
2 Alterations to existing Site Responsibility Schedules
2.1 Without prejudice to the provisions of paragraph 2.4, when a User identified on a Site
Responsibility Schedule becomes aware that an alteration is necessary, it must inform
the DNO 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).
2.2 Where the DNO 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 paragraph 1.7 shall be
followed with regard to the revised Site Responsibility Schedule.
2.3 The revised Site Responsibility Schedule shall then be signed in accordance with the
procedure set out in paragraph 1.8 and distributed in accordance with the procedure set
out in paragraph 1.9, accompanied by a note indicating where the alteration(s) has/have
been made, the new issue number and the date of implementation.
2.4 When a User identified on a Site Responsibility Schedule, or the DNO, 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, the User shall notify
the DNO, or the DNO 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; and
(c) the distribution of the revised Site Responsibility Schedule.
The DNO 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
Distribution Code 1 May 2010
Connection Conditions Page 49
behalf of the DNO and Users (by the persons referred to in paragraph 1.8 of this
appendix) as soon as possible after it has been prepared and sent to Users for
confirmation.
3 Responsible Managers
3.1 Each User and the DNO shall, prior to the date for connection proposed by the User
pursuant to paragraph 10.1.1(c), exchange names and status of managers with authority
to sign Site Responsibility Schedules.
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Connection Conditions Page 50
APPENDIX 2
PROCEDURES RELATING TO OWNERSHIP DIAGRAMS
1 Basic Principles
(a) Where practicable, all the HV Apparatus on any Connection Site shall be
shown on one Ownership 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.
(b) Where more than one Ownership Diagram is unavoidable, duplication of
identical information on more than one Ownership Diagram must be avoided.
(c) The Ownership Diagram must show accurately the current status of the
Apparatus, e.g. whether commissioned or decommissioned. Where
decommissioned, the associated switch bay will be labelled “spare bay”.
(d) Provision will be made on the Ownership Diagram for signifying approvals,
together with provision for details of revisions and dates.
(e) Ownership Diagrams will be prepared in A4 format or such other format as
may be agreed with the DNO.
2 Apparatus to be shown on Ownership Diagrams
1 Busbars
2 Circuit Breakers
3 Disconnector (Isolator) and Switch Disconnectors (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 circuit-breakers
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Connection Conditions Page 51
14 WFPS Transformers, including the lower voltage circuit-breakers
15 Synchronous Compensators
16 Static Variable Compensators
17 Capacitors (including Harmonic Filters)
18 Series or Shunt Reactors
19 Supergrid and Grid Transformers
20 Tertiary Windings
21 Earthing and Auxiliary Transformers
22 Three Phase VTs
23 Single Phase VT & Phase Identity
24 High Accuracy VT and Phase Identity
25 Surge Arrestors/Diverters
26 Neutral Earthing Arrangements on HV Apparatus
27 Fault Throwing Devices
28 Quadrature Boosters
29 Arc Suppression Coils
30 Current Transformers (where separate items)
31 Wall Bushings
3 Recommended Graphical Symbols
Where appropriate, the recommended graphical symbols shown in the attachment to this
Appendix 2 shall be used in the preparation of an Ownership Diagram.
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Connection Conditions Page 52
APPENDIX 3
LIST OF LICENCE STANDARDS
1. ER-P2/5 – Security of Supply, dated October 1978, and NIE amendment sheet, Issue 2,
dated 7 August 1992.
2. PLM-SP-1 – Planning Standards of Security for the Connection of Generating Stations
to the System Issue 1, dated September 1975, and NIE amendment sheet Issue 2, dated
7 August 1992.
3. PLM-ST-4 – CEGB Criteria for System Transient Stability Studies Issue 1, dated
September 1975, and NIE amendment sheet Issue 2, dated 7 August 1992.
4. PLM-ST-9 – Voltage Criteria for the Design of the 400kV and 275kV Supergrid System
Issue 1, dated 1 December 1985 and NIE amendment sheet Issue 2, dated 7 August
1992.
5. ER-P28 – Planning limits for Voltage Fluctuations.
6. ER-P16 – EHV or HV Supplies to Induction Furnaces.
7. ER-P29 – Planning limits for Voltage Unbalance.
8. ER-G5/4- Limits for Harmonics.
9. ER-G12/2 – Application of Protective Multiple Earthing to Low Voltage Networks.
10. EPM-1 – Operational Standards of Security of Supply Issue 2, dated 30 June 1980.
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Connection Conditions Page 53
Recommended Graphical Symbols
Distribution Code 1 May 2010
OC1 – Generation and Demand Forecasting Page 54
Operating Code 1 – Generation and Demand Forecasting
1 Introduction
1.1 Operating Code No. 1 (“OC1”) is concerned with the provision of generation and
Demand forecasts by Users to the DNO in order for the DNO to ensure the proper,
safe and efficient operation of the Distribution System.
1.2 The DNO has an obligation under the Grid Code to provide generation forecasts to the
TSO in order that the TSO can match generation output with Demand. The forecasts
provided by Users under this OC1 will therefore also enable the DNO to comply with
those Grid Code requirements.
1.3 The DNO will be receiving data in respect of Generating Plant connected to the
Distribution System from the TSO under the Grid Code, and will be using that in
relation to the operation of the Distribution System.
2 Objective
2.1 The objectives of OC1 are to set out the requirements for Users to provide estimates to
the DNO to:-
(a) enable the DNO to operate the Distribution System in a proper, safe and
efficient manner and in accordance with its statutory and licence obligations;
and
(b) enable the DNO to comply with its obligations under the Grid Code to provide
generation forecasts to the TSO.
3 Scope
3.1 OC1 applies to the DNO and to Users. Users in OC1 means:
(a) Generators in respect of their Independent Generating Plant connected to the
Distribution System with a Registered Capacity of 1MW and above; and
(b) Demand Customers in respect of their Connections Sites with a Demand of
1MW and above.
4 Procedure
4.1 Each User must provide the following data to the DNO at the time and in the manner
specified:
4.1.1 Generator Loading profiles
Each Generator must, at the request of the DNO, in respect of each of its
Independent Generating Plants with a Registered Capacity of 1MW and
above, submit to the DNO in writing by 0900 hours on the day following the
day on which the request was made an estimate of the Generator Loading
profiles for such Independent Generating Plant for the following Schedule
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OC1 – Generation and Demand Forecasting Page 55
Day, save that it will be for the following three Schedule Days when submitted
on a Friday and the next two Schedule Days when submitted on a Saturday (no
notice being required on a Sunday) and shall be for such longer period as the
DNO may specify, at least one week in advance, to cover holiday periods. Such
estimate will be in the form of half hourly output in MW for such Independent
Generating Plant; and
4.1.2 Demand profile
Each Demand Customer shall at the request of the DNO, in respect of each of
its Connection Sites with a Demand of 1MW and above, submit to the DNO in
writing by 0900 hours on the day following the day on which the request was
made an estimate of its Demand profiles for such Connection Sites for the
following Schedule Day, save that it will be for the next three Schedule Days
when given on a Friday and the next two Schedule Days when given on a
Saturday (no notice being required on a Sunday) and shall be for such longer
period as the DNO may specify, at least one week in advance, to cover holiday
periods. Such estimate will be in the form of half hourly Demand in MW for
such Connection Site.
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OC2 – Outage Planning Page 56
Operating Code 2 – Outage Planning
1 Introduction
1.1 Operating Code No. 2 (“OC2”) is concerned with the co-ordination by the DNO of
planned Generating Unit Outages and Distribution System Outages through various
timescales to enable the efficient operation of the Distribution System.
1.2 OC2 sets out the data required by the DNO from Generators in order for the DNO to
carry out co-ordinated Outage planning and also sets out the information that will be
supplied by the DNO to certain Users.
1.3 In OC2 “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.
2 Objective
2.1 The objectives of OC2 are to:
(a) set out the procedures, timetables and data exchange requirements for the coordination
of Generating Unit and Distribution System Outages in order to
enable the DNO to operate the Distribution System in accordance with its
statutory and licence obligations;
(b) set out the procedures, timetables and data exchange requirements regarding
information to be supplied by the DNO to Users; and
(c) enable the DNO to comply with its Grid Code requirements regarding the
provision of Generating Unit and Distribution System Outage information to
the TSO.
3 Scope
3.1 OC2 applies to the DNO and to Users. Users in OC2 means:
(a) Generators in respect of their Independent Generating Plant with a
Registered Capacity of 1MW and above, CDGUs and Controllable WFPSs,
in each case where connected to the Distribution System;
(b) Demand Customers in respect of their Connection Sites with a Demand of
10MW and above; and
(c) such other Demand Customers as the DNO decides should be informed of
Outage information.
4 Summary
4.1 Under OC2 the interaction between the DNO, Generators and Demand Customers
will be as follows:-
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OC2 – Outage Planning Page 57
(a) each Generator and the DNO in respect of Outages of distribution
connected Independent Generating Plant
with a Registered Capacity of 1MW and
above;
(b) the DNO and each Generator in respect of Distribution System Outages
which may operationally affect Generators
with Independent Generating Plant with a
Registered Capacity of 1MW and above,
CDGUs or Controllable WFPSs connected
to the Distribution System; and
(c) the DNO and Demand Customers in respect of Distribution System Outages
which may operationally affect Demand
Customers with a Demand of 10MW and
above and such other Demand Customers
as the DNO may decide.
4.2 Each User must, in relation to all matters to be undertaken pursuant to this OC2, act
reasonably and in good faith.
4.3 The DNO must, in relation to all matters to be undertaken pursuant to this OC2, act
reasonably and in good faith in the discharge of its obligations.
5 Outage planning procedures for Generators with Independent Generating Plant
with a Registered Capacity of 1MW and above
5.1 Planning for Year 1
5.1.1 By the end of July in each calendar year each Generator in respect of its
Independent Generating Plant with a Registered Capacity of 1MW and
above connected to the Distribution System shall provide the DNO in writing
with its indicative Outage programmes for Year 1.
5.1.2 The indicative Outage programme shall contain the planned Start Date,
planned Finish Date and the Output reduction.
5.2 Planning for Year 0
5.2.1 Each Generator in respect of its Independent Generating Plant with a
Registered Capacity of 1MW and above connected to the Distribution System
shall develop and keep up to date its Outage programme for Year 0.
5.2.2 On request by the DNO, each Generator in respect of its Independent
Generating Plant with a Registered Capacity of 1MW and above connected to
the Distribution System shall as soon as reasonably practicable following the
request provide the DNO in writing with the most up to date version of its
Outage programme for Year 0.
5.2.3 The Outage programme shall contain the planned Start Date, Finish Date and
the Output reduction.
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OC2 – Outage Planning Page 58
6 Outage Planning Procedures for Distribution System Outages
6.1 Planning for Year 1
6.1.1 By the end of May in each calendar year the DNO shall have prepared a plan of
Distribution System Outages scheduled to take place in Year 1 relating to
construction, refurbishment and maintenance works.
6.1.2 By the end of June in each calendar year the DNO shall notify in writing:
(a) each Generator with Independent Generating Plant with a Registered
Capacity of 1MW and above connected to the Distribution System;
(b) each Generator with a CDGU or a Controllable WFPS connected to
the Distribution System;
(c) each Demand Customer with a Demand of 10MW or above; and
(d) such other Demand Customers as the DNO may decide,
of those aspects of the plan which may operationally affect such Users in Year
1. The notification shall include proposed Start Dates and Finish Dates of
relevant Distribution System Outages.
6.1.3 The DNO will indicate to each Generator where a need may exist to use
Intertripping or other measures to allow the security of the Distribution
System to be maintained within the Licence Standards.
6.2 Planning in Year 0
6.2.1 The DNO shall develop and keep up to date the Distribution System Outage
plan for Year 0.
6.2.2 By 11.00 hours each Thursday the DNO shall notify in writing:
(a) each Generator with Independent Generating Plant with a Registered
Capacity of 1MW and above connected to the Distribution System;
(b) each Generator with a CDGU or a Controllable WFPS connected to
the Distribution System;
(c) Each Demand Customer with a Demand of 10MW or above; and
(d) such other Demand Customers as the DNO may decide,
of those aspects of the plan which may operationally affect such Users in the
following one week period beginning on the following Monday. The notification
to the User shall include proposed Start Dates and Finish Dates of relevant
Distribution System Outages.
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OC2 – Outage Planning Page 59
6.3 The DNO will indicate to each Generator where a need may exist to use Intertripping
or other measures to allow the security of the Distribution System to be maintained
within the Licence Standards.
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OC3 – Demand Control Page 60
Operating Code 3 – Demand Control
1 Introduction
1.1 Operating Code No. 3 (“OC3”) sets out the procedures to be followed by the DNO to
permit a reduction in Demand, which in many instances will be initiated by the TSO
acting in accordance with the TSO Licence:
(a) in the event that there are insufficient Generating Plant, Independent
Generating Plant, Demand Side Units or transfers across any Interconnectors
and the Inter-jurisdictional Tie Lines between Northern Ireland and the
Republic of Ireland available to meet Demand in all or any part of the NI
System; and/or
(b) in the event of problems on any part of the NI System, including, without
limitation, unacceptable voltage levels and thermal overloads; and/or
(c) where there are insufficient Generating Plant, Independent Generating Plant,
Demand Side Units or transfers to meet Demand in all or any part of the
Other Transmission System and/or in the event of problems on the Other
Transmission System in circumstances where the TSO is able to assist the
Other TSO and where doing so would not have a detrimental effect on the
security of the NI System.
1.2 It covers both transient shortfalls of generation following a sudden loss of generation
and steady state shortfalls of generation.
1.3 The Demand Control arrangements provide for the utilisation of controllable Load
blocks on the NI System, for example, by radio teleswitching implemented by the
TSO.
1.4 OC3 deals with the following:-
(a) Demand Customer Voltage Reduction initiated by the TSO or the DNO and in
each case implemented by the DNO;
(b) Planned Manual Disconnection (including Rota Load Shedding) initiated by
the TSO and implemented by the DNO;
(c) Emergency Manual Disconnection initiated and implemented by the TSO;
(d) protection of supply to any part of the NI System where system security is
weak; and
(e) Disconnection of Load blocks by operation of Automatic Load Shedding
Devices to preserve overall NI System security.
Some Users will be affected by some or all of the above actions, whether implemented
by the TSO or the DNO.
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OC3 – Demand Control Page 61
1.5 The term “Demand Control” is used in OC3 to describe any of the methods of
controlling Demand set out in paragraph 1.4.
1.6 The type of Demand Control utilised in any particular case will depend upon the
amount of time between the TSO or the DNO becoming aware of the need to
implement Demand Control and the time at which it needs to be implemented. In the
event of a sudden and unexpected loss of generation and/or NI System problems and,
subject to the circumstances set out in paragraph 1.1.3, in the event of a sudden and
unexpected loss of generation on the Other Transmission System and/or Other
Transmission System problems, the requisite Demand Control will normally be
achieved by means of Automatic Load Shedding but, occasionally, Emergency
Manual Disconnection may be required. The amount of time available in which to
implement Demand Control will also determine whether Demand Control will be
implemented before voltage reduction. In all cases when Demand Control is
necessary, Demand Disconnection will normally be the last option.
1.7 Demand Control shall not, so far as possible, be exercised in respect of Protected
Demand Customers. OC3, therefore, applies subject to this exclusion.
2 Objective
The objective of OC3 is to detail the provisions to be undertaken by the DNO required
to achieve a reduction in Demand to avoid or relieve operating problems on all or any
part of the NI System and, subject to the circumstances set out in paragraph 1.1.3, on
the Other Transmission System. Subject to paragraph 1.7, the DNO will utilise
Demand Control in a manner which does not unduly discriminate against, or unduly
prefer, any one or any group of Demand Customers.
3 Scope
3.1 This section applies to the DNO and to Users. Users in OC4 means:
(a) Suppliers;
(b) Generators; and
(c) Demand Customers.
4 Procedures
4.1 Demand Customer Voltage Reduction
4.1.1 The DNO will, insofar as it is able, organise the Distribution System and make
such other arrangements as are necessary so that a 6 per cent reduction of
voltage supplied to all or any group of Demand Customers on a particular part
of the Distribution System can be implemented.
4.1.2 The arrangement will provide for two 3 per cent stages of voltage reduction,
which can be applied to all or selected groups of Demand Customers.
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OC3 – Demand Control Page 62
4.1.3 The DNO will, when instructed by the TSO and/or when it considers it
necessary, implement Demand Customer Voltage Reduction of either 3 per
cent or 6 per cent.
4.1.4 The DNO will, when instructed by the TSO and/or when it considers it
necessary, remove the voltage reduction implemented pursuant to paragraph
4.1.3.
4.2 Planned and Emergency Manual Disconnection
Planned Manual Disconnection
4.2.1 Planned Manual Disconnection is the procedure adopted by the DNO when the
TSO, in accordance with the Grid Code, notifies the DNO that insufficient
generation will be available to meet Demand in all or any part of the NI System
and that Demand Control is required.
4.2.2 Where the TSO has notified the DNO in accordance with the Grid Code that
Demand Control is required, the TSO may then instruct the DNO in
accordance with the Grid Code to implement Planned Manual Disconnection
and the DNO shall implement such Planned Manual Disconnection in
accordance with this OC3.
4.2.3 The DNO will restore the connections removed by Planned Manual
Disconnection pursuant to paragraph 4.2.2 when instructed by the TSO in
accordance with the Grid Code to do so.
4.2.4 Where Demand Control is required to continue for a protracted period rotation
of Disconnection under a Rota Load Shedding procedure may be required to
ensure equitable treatment, insofar as practicable, for all Demand Customers as
further detailed in paragraphs 4.2.5 and 4.2.6.
4.2.5 The DNO, in conjunction with the TSO, will arrange for the purposes of Rota
Load Shedding, insofar as it is able, that the Demand on the NI System is
arranged in groups of approximately 5 per cent of total Demand (as a
percentage at time of winter peak) so that any or all such groups can be
Disconnected when the TSO issues instructions to the DNO in accordance with
the Grid Code.
4.2.6 Where Disconnection is to be prolonged, the DNO will, where possible, utilise
Disconnection rotas where approximately 5 per cent groups are interchanged to
ensure (so far as possible) equitable treatment of Demand Customers.
Emergency Manual Disconnection
4.2.7 Emergency Manual Disconnection is utilised by the TSO when a loss of
generation or a mismatch of generation output and Demand is such that there is
an operational requirement to shed Load in circumstances where it is not
possible to give reasonable notice in order to maintain a Regulating Margin
between generation output and Demand and in certain circumstances to deal
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OC3 – Demand Control Page 63
with operating problems such as unacceptable voltage levels and thermal
overloads.
4.2.8 The TSO will, when it considers it necessary, implement Emergency Manual
Disconnection.
4.3 Demand Control with weak or reduced NI System capabilities
4.3.1 This section covers the situation where the DNO or the TSO may wish to
initiate Demand Control to maintain partial supplies to a part of the NI System
which cannot support the full area Demand of that part of the NI System.
4.3.2 It applies to circumstances where the DNO or the TSO wish to allow for fault
contingencies more severe than envisaged in the Licence Standards because the
impact of these contingencies on the NI System would be unacceptable.
4.3.3 Where the DNO or the TSO considers that arrangements should be put in place
to enable Demand Control to be effected in the circumstances outlined in
paragraph 4.3.1, either may effect such arrangements.
4.3.4 Load shedding caused by these arrangements will be assimilated into Load
shedding caused by the Automatic Load Shedding scheme detailed in
paragraph 4.4 to ensure no Demand Customer or group of Demand
Customers is unfairly discriminated against.
4.4 Automatic Load Shedding
4.4.1 Under generation shortfall conditions a Frequency graded Automatic Load
Shedding scheme is utilised by the TSO to prevent Frequency collapse on the
NI System and to restore the balance between generation output and Demand.
4.4.2 The Demand on the NI System subject to Automatic Load Shedding will be
split into discrete blocks. The number, location, size and the associated low
Frequency settings of these blocks will be as determined by the TSO on a rota
basis insofar as possible and communicated to the DNO.
4.4.3 Where conditions are such that, following Automatic Load Shedding, and the
subsequent recovery of Frequency on the NI System, it is not possible to
restore a large proportion of the total Demand so Disconnected within a
reasonable period of time, the DNO may receive an instruction from the TSO to
implement additional Disconnection manually to restore an equivalent amount
of the Demand which has been Disconnected automatically. It will then effect
that instruction.
4.4.4 For the avoidance of doubt, no Demand shed by operation of Automatic Load
Shedding Devices will be restored by the DNO without the specific instruction
of the TSO in accordance with the Grid Code.
4.5 General
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OC3 – Demand Control Page 64
Suppliers should note that although implementation of Demand Control in respect of
their Demand Customers is not, in general, exercisable by them, their Demand
Customers may be affected by Demand Control. The contractual arrangements of
Suppliers with their Demand Customers may, accordingly, need to reflect this.
5 Fuel Security Code
Each Supplier agrees to comply with the Fuel Security Code to the extent it is
expressed to apply to it and with any instructions issued by the TSO or the DNO
pursuant to the Fuel Security Code.
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OC4 – Operational Liaison Page 65
Operating Code 4 – Operational Liaison
1 Introduction
1.1 Operating Code No. 4 (“OC4”) sets out the requirements for the exchange of
information between the DNO and Users in relation to Operations and Events on the
Total System which will have (or may have) or have had (or may have had) an
Operational Effect:-
(a) on a User System in the case of an Operation and/or Event occurring on the
Distribution System or the Transmission System; and
(b) on the Distribution System in the case of an Operation and/or Event occurring
on a User System;
where there is no other requirement for exchange of information or liaison specified in
any other part of the Distribution Code.
1.2 Where there is an obligation on the DNO under the Grid Code to report an Operation
and/or Event on the Distribution System to the TSO, the DNO may include in that
report information which it has been given by a User relating to an Operation and/or
Event on the User System which caused or contributed to the Event on the
Distribution System or, in the case of an Operation on the User System, caused the
DNO to undertake an Operation on the Distribution System.
1.3 Where the Grid Code contains an equivalent provision allowing the DNO to pass on
information it has received under the Grid Code in relation to Operations and/or
Events on the Transmission System, or on the system of users under the Grid Code,
that will form part of the information communicated to Users under this OC4. The
provisions of this OC4 allowing the DNO to pass information it has received under the
Grid Code will only have effect to the extent that the DNO is allowed to pass that
information on to Users pursuant to the Grid Code.
2 Objective
2.1 The objective of this OC4 is to set out the requirements and procedures for the
exchange of information between the DNO and Users in order that the implications of
an Operation and/or Event can be considered and the possible risks arising from it can
be assessed and appropriate action taken by either the DNO or the User as applicable in
order to maintain the integrity of the Distribution System and the relevant User
System. OC4 does not seek to deal with any actions arising from the exchange of
information, but merely with that exchange.
3 Scope
3.1 OC4 applies to the DNO and to Users. Users in this OC4 means:
(a) Generators in respect of their Generating Units connected to the Distribution
System at 33kV; and
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OC4 – Operational Liaison Page 66
(b) Demand Customers in respect of their Connection Sites connected to the
Distribution System at 33kV; and
(c) Regarding notification to the DNO, Users in respect of their User Systems
connected to the Distribution System at 6.6kV or 11kV.
4 Procedure
4.1 Requirement to notify Operations
4.1.1 DNO notification
In the case of an Operation on the Distribution System which will have, or
may have, an Operational Effect on a 33kV User System, the DNO will
(unless the notifying requirement arises under any other part of the Distribution
Code) notify the User, or Users, whose System(s) will, or may in the opinion
of the DNO, be so affected in accordance with this OC4. The provisions of this
paragraph 4.1.1 shall also apply to circumstances where an Operation on the
Transmission System will have, or may have, an Operational Effect on a
User System where the DNO has been notified of such an Operation by the
TSO under the Grid Code.
4.1.2 User Notification
In the case of an Operation on a 33kV User System which will have or may
have an Operational Effect on the Distribution System the User will (unless
the notifying requirement arises under any other part of the Distribution Code)
notify the DNO in accordance with this OC4. Following notification by the
relevant User, the DNO will notify any other User or Users on whose
System(s) the Operation will (or, in the DNO’s reasonable opinion, may) have
an Operational Effect. The DNO may also notify the TSO if the Operation
will (or, in the DNO’s reasonable opinion, may) have an Operational Effect on
the Transmission System, in accordance with its obligations under the Grid
Code.
4.1.3 Examples
Whilst in no way limiting the general requirement to notify in advance as set out
in paragraphs 4.1.1 and 4.1.2, the following are examples of scheduled or
planned actions for which notification will be required under this OC4 if they
will, or may, have an Operational Effect:-
(a) the planned operation (other than, in the case of a User, at the
instruction of the DNO) of any circuit breaker or isolator or any
sequence or combination of the two; and
(b) Voltage Control.
4.1.4 Nature of notification
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(a) A notification under paragraph 4.1.1 or 4.1.2 (save where the
notification is to be given to a Demand Customer, in which event the
provisions of paragraph 4.1.5 shall apply) must 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. It must include the name of the
individual reporting the Operation on behalf of the DNO or the User, as
the case may be. The recipient may ask questions to clarify the
notification and the notifying party shall use its reasonable endeavours to
provide the necessary information.
(b) A notification which is to be given under paragraph 4.1.1 or 4.1.2 to a
Demand Customer will not contain the information specified in
paragraph 4.1.4 but may indicate that there will be, or is likely to be, an
incident on the Distribution System, the general nature of the incident
(but not the cause of the incident) and, if known, in circumstances where
power supplies are thought likely to be affected, the estimated time of
cessation and return to service.
4.1.5 Timing
A notification under paragraph 4.1.1 or 4.1.2 must be given as far in advance as
practicable 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.
4.1.6 Recording
The notification shall be given in writing whenever possible. If there is
insufficient time before the Operation is scheduled to take place for notification
to be given in writing, then notification shall be given orally and, if either party
requests, it shall be written down by the sender and dictated to the recipient who
shall write it down and repeat each phrase as received and, on completion, shall
repeat the notification in full to the sender and check that it has been accurately
recorded.
4.1.7 User notification in respect of 6.6kV and 11kV connections
The DNO may, acting reasonably, require Users in respect of their User
Systems connected to the Distribution System at 6.6kV or 11kV, to notify the
DNO of an Operation on their Systems, such notification to be in accordance
with the provisions of paragraphs 4.1.2 to 4.1.6 inclusive.
4.2 Requirement to notify Events
4.2.1 DNO notification
In the case of an Event on the Distribution System which has had (or may have
had) an Operational Effect on a User System, the DNO will (unless the
notifying requirement arises under any other part of the Distribution Code)
notify the User or Users whose System(s) have been (or in the reasonable
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opinion of the DNO may have been) so affected, in accordance with this OC4.
The provisions of this paragraph 4.2.1 shall also apply to circumstances where
an Operational Effect on the User System was caused by an Event on the
Transmission System, provided that the DNO’s duty to notify a User shall be
solely a duty to pass on the information that the DNO has received from the
TSO.
4.2.2 User notification
In the case of an Event on a User System which has had (or may have had) an
Operational Effect on the Distribution System the User will (unless the
notifying requirement arises under any other part of the Distribution Code)
notify the DNO in accordance with this OC4. Following notification by the
relevant User, the DNO will notify any other User or Users on whose System
the Event has had (or, in the DNO’s reasonable opinion, may have had) an
Operational Effect. The DNO may also notify the TSO if the Event has had
(or, in the DNO’s reasonable opinion may have had) an effect on the
Transmission System, in accordance with its obligations under the Grid Code.
4.2.3 Examples
Whilst in no way limiting the general requirement to notify set out in paragraphs
4.2.1 and 4.2.2, the following are examples of situations where notification will
be required under this OC4 if they have had, or may have had, 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;
(e) breakdown of, or faults on, control, communications or metering
equipment;
(f) increased risks of Protection operation.
4.2.4 Nature of notification
(a) A notification under paragraphs 4.2.1 or 4.2.2 (save where the
notification is to be given to a Demand Customer, in which event the
provisions of paragraph 4.2.5 shall apply) will be of sufficient detail to
describe the Event (although it need not state the cause) and so enable
the recipient of the notification reasonably to consider and assess the
implications and risks arising. The recipient may ask questions to clarify
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the notification and the notifying party shall use its reasonable
endeavours to provide the necessary information.
(b) A notification which is to be given under paragraph 4.2.1 or 4.2.2 to a
Demand Customer will not contain the information specified in
paragraph 4.2.4 but may indicate that there has been an incident on the
Distribution System, the general nature of the incident (but not the
cause of the incident) and, if known, in circumstances where power
supplies have been affected, an estimated time of return to service.
4.2.5 Recording
Notification shall be given orally and, except in the case of emergency, if either
party requests, shall be written down by the sender and dictated to the recipient
who shall write it down and repeat each phrase as received and, on completion,
shall repeat the notification in full to the sender and check that it has been
accurately recorded.
4.2.6 Timing
A notification under paragraph 4.2.1 or 4.2.2 shall be given as soon as possible
after the occurrence of the Event, or the time that the Event is known of or
anticipated by the giver of the notification under this OC4, and in any event
within 15 minutes of such time.
4.2.7 User notification in respect of 6.6kV and 11kV connections
The DNO may, acting reasonably, require Users in respect of their User
Systems connected to the Distribution System at 6.6kV or 11kV, to notify the
DNO of an Event on their Systems, such notification to be in accordance with
the provisions of paragraphs 4.2.2 to 4.2.6 inclusive.
4.3 Significant Incidents
4.3.1 Where the DNO notifies a User of an Event under paragraph 4.2.1 which the
User considers has had or may have had a significant effect on that User’s
System, that User may require the DNO to report that Event in writing in
accordance with the provisions of OC5 in which event it will, within one
Business Day, notify the DNO accordingly.
4.3.2 Where a User notifies the DNO under paragraph 4.2.2 of an Event which the
DNO considers has had or may have had a significant effect on the Distribution
System, the DNO may require the User to report that Event in writing in
accordance with the provisions of OC5 in which event it will, within one
Business Day, notify that User accordingly.
4.3.3 Events which a User requires the DNO to report in writing pursuant to
paragraph 4.3.1 and Events which the DNO requires a User to report in writing
pursuant to paragraph 4.3.2 are known as “Significant Incidents”.
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4.3.4 Without limiting the general description set out in paragraphs 4.3.1 and 4.3.2, a
Significant Incident will include an Event having an Operational Effect which
results in, or is likely to result in, the following:-
(a) tripping of Plant and/or Apparatus either manually or automatically;
(b) voltage outside statutory limits;
(c) System Frequency outside statutory limits;
(d) System instability; or
(e) System overloads.
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Operating Code 5 – Operational Event Reporting and Information Supply
1 Introduction
1.1 Operating Code No. 5 (“OC5”) sets out the requirements for reporting in writing and,
where appropriate, more fully those Significant Incidents which initially were reported
to the DNO or a User orally under OC4 and the requirements for the provision to the
DNO of information to enable it to prepare analyses and assessments of policies in the
Distribution Code.
1.2 Where the Grid Code contains a provision allowing the DNO to pass on information it
has received under the Grid Code in relation to Significant Incidents on the
Transmission System, or on the system of users under the Grid Code, that will form
part of the information communicated to Users under this OC5. The provisions of this
OC5 allowing the DNO to pass information it has received under the Grid Code will
only have effect to the extent that the DNO is allowed to pass that information on to
Users pursuant to the Grid Code.
2 Objective
2.1 The objective of OC5 is to facilitate:-
(a) the provision of more detailed information in writing of Significant Incidents;
(b) the provision of information aimed at enabling the Distribution System to be
operated in accordance with the Distribution Code; and
(c) the assessment of the effectiveness of policies adopted in accordance with the
Distribution Code.
3 Scope
4.4 OC5 applies to the DNO and to Users. Users in this OC5 means:
(a) Generators in respect of their Generating Units connected to the Distribution
System at HV; and
(b) Demand Customers in respect of their Connection Sites connected to the
Distribution System at HV.
4 Procedure
4.1 Written reports of Events
4.1.1 In the case of a Significant Incident which has been notified as an Event by the
DNO to a User pursuant to OC4, the DNO shall provide a written report to the
User in accordance with this OC5.
4.1.2 In the case of a Significant Incident which has been notified as an Event by a
User to the DNO pursuant to OC4, the User shall provide a written report to
the DNO in accordance with this OC5.
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4.1.3 Form of Report
(a) A report under paragraph 4.1.1 or 4.1.2 shall, in the case of a report by
a User, be addressed to the DNO and marked for the attention of the
Distribution Service Centre Manager and, in the case of a report by the
DNO to a User, be addressed to the User and marked for the attention of
the person notified to the DNO by the User in writing from time to time
for this purpose (or in the absence of notification, to the Company
Secretary).
(b) In either case, the report will contain a written confirmation of the oral
notification given under OC4 together with such further information
which has become known relating to the Significant Incident since the
oral notification under OC4. The report shall, as a minimum, contain
those matters specified in Appendix 1 to this OC5. Appendix 1 is not
intended to be exhaustive.
(c) Whilst the report need not state the cause of the Significant Incident, it
shall contain an indication as to whether the cause has been ascertained
and whether it is thought likely by the party issuing the report that the
matter which caused the Significant Incident will recur. The recipient
may raise questions to clarify the report.
4.2 Timing
4.2.1 Where the DNO is required to produce a written report under paragraph 4.1.1,
it shall do so as soon as possible and in any event within two Business Days
after notification by the User under paragraph 4.3.1 of OC4. In the event that
the DNO is unable to provide a full report within this timescale, it shall provide
to the User a preliminary report containing such information as is then known to
the DNO not later than two Business Days after the notification by the User
under paragraph 4.3.1 of OC4 and shall provide such up-dates thereafter as the
User may reasonably require. A full report shall then be provided to the User as
soon as the DNO is able.
4.2.2 Where a User is required to produce a written report under paragraph 4.1.2, it
shall do so as soon as possible and in any event within two Business Days after
notification by the DNO under paragraph 4.3.2 of OC4. In the event that the
User is unable to provide a full report within this timescale, it shall provide to
the DNO a preliminary report containing such information as is then known to
the User not later than two Business Days after the notification by the DNO
under paragraph 4.3.2 of OC4 and shall provide such updates thereafter as the
DNO may reasonably require. A full report shall then be provided to the DNO
as soon as the User is able.
4.3 Responsible officers
The DNO and each User shall nominate responsible officers in order to establish
communication channels to enable timely and adequate flows of information between
the DNO and Users to be maintained and thus to ensure the effectiveness of this OC5.
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4.4 Provision of reports to other Users and the TSO
Whenever a User has provided a written report in respect of a Significant Incident to
the DNO in accordance with paragraph 4.1.2, the DNO shall consider whether the
System of another User (or Users) or the Transmission System has been or is likely to
have been materially affected. If the DNO considers that another User System (or
Systems) or the Transmission System has been or is likely to have been so affected,
the DNO shall notify the User which prepared the report accordingly and the User shall
supply an extract from its report, containing only the technical information (and no
information of commercial value) which was set out in the report, to the other Users
and/or the TSO identified by the DNO.
4.5 The provision of information to the DNO
4.5.1 The DNO may require (to the extent not supplied under any other provision of
the Distribution Code) information of a technical (but not of a commercial)
nature to be supplied by Users under this paragraph 4.5 to enable it to undertake
the following:-
(a) the preparation of Distribution System and/or User System appraisal
statements;
(b) surveys of Distribution System and/or User System conditions;
(c) analysis and validation of policies in the Distribution Code; and
(d) analyses of the DNO equipment performance;
insofar as such information is necessary to enable the DNO to fulfil its
obligations relating to the operation of the Distribution System.
4.5.2 When the DNO requires information from a User or Users for the purposes set
out in paragraph 4.5.1 it shall send a written request to the User or Users
setting out the information it reasonably requires, the reasons (in such detail as
the DNO reasonably considers to be appropriate) why such information is
required and the time by which it reasonably requires a response. Normally this
will be within two Business Days.
4.5.3 The User or Users will use all reasonable endeavours to respond in writing
within the time stated. However, a User will not be obliged to supply the
information requested by the DNO to the extent that it considers that it is not
reasonable to comply with the request. In such circumstances, the User must, in
its written response to the DNO, state such reason in sufficient detail to enable
the DNO to consider whether the User is acting reasonably in refusing to supply
the information.
4.5.4 Although the request will set out the information required, an indication of the
sort of information that may be requested is set out in Appendix 2 to this OC5.
The list contained in Appendix 2 shall not limit the information which may be
requested, but is merely given by way of example.
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4.5.5 The information supplied to the DNO pursuant to this paragraph 4.5 will be
used by the DNO only for the purposes set out in paragraph 4.5.1.
5 Statutory event reporting procedure
Nothing in this OC5 shall be construed as relieving Users from their duty to report
events in accordance with the Electricity Supply Regulations (N.I.) in so far as they
apply to Users.
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OC5 – Appendix 1
Matters, if applicable to the Significant Incident, to be included in a written report given in
accordance with paragraph 4.1
1 Time and date of Significant Incident.
2 Location.
3 Plant and/or Apparatus involved.
4 Brief description of Significant Incident.
5 Estimated time and date of return to service.
6 Supplies/generation interrupted and duration of interruption.
7 Generating Unit – MVAr performance achieved.
8 Any other information which either the DNO or the User reasonably considers that the
other might reasonably require in relation to the Significant Incident.
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OC5 – Appendix 2
Indication of the sort of information that may be requested under paragraph 4.5
1 VOLTAGE
Time and date
Location
Target volts
Actual volts
Reason if different
2 MW/MVAr CAPABILITY
Time and date
Location
Set identification
Generating Unit performance parameters (List to be included)
3 TRANSFERS AT CONNECTION POINT
Time and date
Location
Direction and magnitude of MW and MVAr flows
4 FAULT LEVELS AT CONNECTION POINT
Time and date
Location
Fault infeed
The necessary data to enable (single phase to earth and three phase symmetrical) fault
levels to be calculated
5 PROTECTION PERFORMANCE UNDER FAULT CONDITIONS
Time and date
Location
Differences between anticipated and actual performance.
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Operating Code 6 – Safety Co-ordination
1 Introduction
1.1 Operating Code No. 6 (“OC6”) specifies the standard procedures which are to be
followed by the DNO and Users for the co-ordination, establishment and maintenance
of necessary Safety Precautions when work and/or testing (other than System Tests,
which are covered by OC9 and the type of tests covered in OC10) is to be carried out
on or near the Distribution System or a User System and when, for this to be done
safely, Safety Precautions are required on the Distribution System and on the User’s
System.
1.2 Where, by reason of the design of any HV Apparatus on which Safety Precautions
are to be applied, it is not practicable to apply Safety Precautions on such HV
Apparatus, the Safety Precautions shall be applied at the most appropriate point(s) on
the User’s Plant and Apparatus to achieve Safety From The System on the HV
Apparatus on which Safety From The System is to be achieved.
1.3 OC6 does not apply to a situation in which Safety Precautions need to be agreed solely
between Users and other persons connected to the Distribution System.
1.4 OC6 does not seek to impose a particular set of Safety Rules on the DNO or Users; the
Safety Rules to be adopted and used by the DNO and each User shall be those chosen
by each.
1.5 The procedures set out in this OC6 do not refer expressly to a situation in which both
the DNO and a User require the other to implement Safety Precautions at the same
time. In such circumstances the relevant procedures of this OC6 should be applied
twice, once with the DNO acting as Implementing Safety Co-ordinator and once with
the User acting in that role.
2 Objective
2.1 The objective of this OC6 is to achieve Safety From The System when work and/or
testing on or near either a User’s System or the Distribution System necessitates the
provision of Safety Precautions on the Distribution System and a User’s System..
3 Scope
3.1 OC6 applies to the DNO and to Users. Users in OC6 means
(a) Generators in respect of their Generating Units connected to the Distribution
System at HV; and
(b) Demand Customers in respect of their Connection Sites connected to the
Distribution System at HV.
4 Procedure
4.1 The procedures set out in the remainder of this OC6 apply to the DNO and to Users in
respect of Generating Units or Connection Sites connected to the Distribution System
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at 33kV or above. In the event of any inconsistency between the procedures set out in
this OC6 and the procedures (if any) set out in such User’s Connection Agreement,
the procedures set out in this OC6 shall prevail.
4.2 For Users in respect of Generating Units or Connection Sites connected to the
Distribution System below 33kV, such Users and the DNO shall apply the processes
and procedures set out in Safety Rules Guidance Document 4 (“SRG 4”) of the NIE
Safety Rules. In the event of any inconsistency between the processes and procedures
set out in SRG 4 and the procedures (if any) set out in such User’s Connection
Agreement, the procedures set out in SRG 4 shall prevail save where such Connection
Agreement makes it explicit that the procedures therein shall prevail.
5 Approval of Local Safety Instructions
5.1 In accordance with the timing requirements of its Connection Agreement, each User
shall supply to the DNO a copy of its Local Safety Instructions, if any, relating to its
side of the Connection Point at each Connection Site. In accordance with the timing
requirements of each Connection Agreement, the DNO shall supply to each User a
copy of the DNO’s Local Safety Instructions, if any, relating to the DNO side of the
Connection Point at each Connection Site. Prior to connection and in accordance with
the timing requirements of the relevant Connection Agreement, the DNO and the User
must have approved each other’s Local Safety Instructions dealing with Isolation and
Earthing.
5.2 If the party required to give approval requires, for that approval to be given, more
stringent provisions relating to Isolation and/or Earthing (including relating to
Earthing Devices) (and to the extent that these are not unreasonable), the other party
will make such changes as soon as reasonably practicable to the provisions in its Local
Safety Instructions relating to Isolation and/or Earthing (including relating to
Earthing Devices) affecting the Connection Site (which may of course need to cover
the application of Isolation and/or Earthing at a place remote from such Connection
Site, depending upon the System layout). There is no right to withhold approval on the
grounds that the party required to approve reasonably believes the provisions relating to
Isolation and/or Earthing (including Earthing Devices) are too stringent.
5.3 If, following approval, a party wishes to change the provisions in its Local Safety
Instructions relating to Isolation and/or Earthing (including Earthing Devices), 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 paragraph 5.2 will apply.
6 Safety Co-ordinators
6.1 The DNO and each User will at all times have nominated a person or persons to be
responsible for the co-ordination of Safety Precautions at each Connection Point,
when work and/or testing is to be carried out on or near a System which necessitates
the provision of Safety Precautions on (or relating to) HV Apparatus, pursuant to this
OC6 (“Safety Co-ordinator(s)”). A Safety Co-ordinator may be responsible for the
co-ordination of safety on (or relating to) HV Apparatus at more than one Connection
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Point. It should be noted that, for the purposes of this OC6, the Safety Co-ordinator’s
role is limited to the co-ordination of Safety Precautions. The Safety Co-ordinator
will not necessarily but may undertake the physical implementation of Safety
Precautions.
6.2 Each User shall, prior to its Plant and Apparatus being connected to the Distribution
System, in accordance with any timing provisions of the Connection Agreement or, in
the absence of such provisions, as far in advance as possible, give notice in writing to
the DNO of the identity of its Safety Co-ordinator(s), along with contact details, and
shall update the written notice (i) whenever there is a change to the identity or contact
details of its Safety Co-ordinator(s), and (ii) annually on 1 April each year.
6.3 The DNO shall at the time of a User being connected to the Distribution System, in
accordance with the timing provisions of the Connection Agreement or, in the absence
of such provisions, as far as possible in advance, give notice in writing to that User of
its Safety Co-ordinator(s), along with contact details, and shall update the written
notice (i) whenever there is a change to the identity or contact details of the Safety Coordinator(
s), and (ii) annually on 1 April each year.
6.4 If work and/or testing is to be carried out on or near a System which necessitates the
provision of Safety Precautions on (or relating to) HV Apparatus in accordance with
the provisions of this OC6, the Safety Co-ordinator who is identified on the relevant
Site Responsibility Schedule as responsible for the HV Apparatus on which or in
relation to which Safety From The System is to be achieved (the “Requesting Safety
Co-ordinator”) shall contact the Safety Co-ordinator who is identified on that same
Site Responsibility Schedule as being responsible for the HV Apparatus which is
connected at the Connection Point to the HV Apparatus on which Safety From The
System is required (the “Implementing Safety Co-ordinator”), to co-ordinate the
Safety Precautions.
7 RISSP
7.1 OC6 sets out the procedures for utilising the Record of Inter-System Safety
Precautions (“RISSP”).
7.2 The form set out in Appendix A and designated as “RISSP-A”, shall be used by the
Requesting Safety Co-ordinator, and that in Appendix B and designated as “RISSPB”,
shall be used by the Implementing Safety Co-ordinator.
7.3 RISSP-A shall have written or printed on it an identifying number, comprising a unique
prefix which identifies the location at which it is issued, and a unique (for each User or
the DNO, as the case may be) serial number consisting of four digits and the suffix
“R”.
7.4 At the time that the User first gives notice to the DNO of its Safety Co-ordinators,
each User shall apply in writing to the DNO for the DNO’s approval of its proposed
prefix. The DNO shall consider the proposed prefix to see if it is the same as (or
confusingly similar to) a prefix used by the DNO or another User and shall, as soon as
possible (and in any event within ten days), respond in writing to the User with its
approval or disapproval. If the DNO disapproves, it shall explain in its response why it
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has disapproved and will suggest an alternative prefix and the User shall either notify
the DNO in writing of its acceptance of the suggested alternative prefix or it shall apply
in writing to the DNO with revised proposals and the above procedure shall apply to
that application.
8 Safety Precautions on or Relating to HV Apparatus
8.1 Safety Precautions
For the purpose of the co-ordination of safety under OC6 relating to HV Apparatus,
the term “Safety Precautions” means Isolation and/or Earthing.
8.2 Agreement of Safety Precautions
8.2.1 When the DNO or a User wishes to carry out work and/or testing on its System
and it is of the opinion that, for this to be done safely, Safety Precautions are
required on the DNO’s HV Apparatus (in the case of a User), or on or relating
to the HV Apparatus of a User (in the case of the DNO), the Requesting
Safety Co-ordinator will contact the Implementing Safety Co-ordinator for
the part of the System on which (or relating to which) the Safety Precautions
are, in his reasonable opinion, required, in order to agree in accordance with the
procedure contained in this paragraph 8, the Location at which the Safety
Precautions will be implemented or applied.
8.2.2 When the DNO wishes to carry out work and/or testing on the Distribution
System and it is of the opinion that, for this to be done safely, Safety
Precautions are required on (or relating to) the System of more than one User
the provisions of this paragraph 8 shall be followed with regard to each User
separately.
8.3 Agreement of Isolation
8.3.1 The Requesting Safety Co-ordinator shall inform the Implementing Safety
Co-ordinator of the HV Apparatus on which Safety From The System is to
be achieved and they will need to reach agreement on the Location(s) at which
Isolation is to be established on (or relating to) the Implementing Safety Coordinator’s
System.
8.3.2 The Implementing Safety Co-ordinator shall then promptly inform the
Requesting Safety Co-ordinator of the following:
(a) for each Location, the identity (by means of name and numbering or
position, as applicable) of each point of Isolation; and
(b) whether Isolation is to be achieved by an Isolating Device in the
isolating position or by an adequate physical separation or sufficient gap
or by disablement (by means of switching or dismantling) of Plant
and/or Apparatus so that electrical energy cannot pass from the
Apparatus (or, in the case of Plant, from the associated Apparatus) to
the HV Apparatus, other than by an Isolating Device.
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8.3.3 The Implementing Safety Co-ordinator shall maintain and secure each point of
Isolation in accordance with the relevant Local Safety Instructions.
8.4 Agreement of Earthing
8.4.1 If, in addition to the Isolation requested under paragraph 8.3, the Requesting
Safety Co-ordinator requires Earthing, he shall notify this requirement to the
Implementing Safety Co-ordinator and they will need to reach agreement on
the Location(s) at which Earthing is to be established on the Implementing
Safety Co-ordinator’s System.
8.4.2 The Implementing Safety Co-ordinator shall then promptly inform the
Requesting Safety Co-ordinator for each Location, the identity (by means of
HV Apparatus name and numbering or position, as is applicable) of each point
of Earthing.
8.4.3 The Implementing Safety Co-ordinator shall maintain and secure each point of
Earthing in accordance with the relevant Local Safety Instructions.
8.5 In the event of disagreement
8.5.1 In any case where the Requesting Safety Co-ordinator and the Implementing
Safety Co-ordinator are unable to agree the Location of the Isolation and (if
requested) Earthing, it 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 Ownership Diagram or, in the case where, by reason of the
design of any HV Apparatus on which Safety Precautions are to be applied, it
is not practicable to apply Safety Precautions on such HV Apparatus, it shall
be at the most appropriate point(s) on the User’s Plant and/or Apparatus to
achieve Safety From The System on the HV Apparatus on which Safety From
The System is to be achieved, as determined by the DNO.
8.6 Implementation of Isolation and Earthing
8.6.1 Once the Location of Isolation and (if requested) Earthing are agreed in
accordance with paragraphs 8.3 and 8.4 above, the following procedure will
apply:
(a) the Implementing Safety Co-ordinator will ensure the implementation
of the Isolation;
(b) the Implementing Safety Co-ordinator will confirm to the Requesting
Safety Co-ordinator that the Isolation has been established on his
System;
(c) when the Implementing Safety Co-ordinator has confirmed the
establishment of Isolation in accordance with (b) above, the Requesting
Safety Co-ordinator shall confirm to the Implementing Safety Coordinator
the establishment of relevant Isolation on his System and
request, if it has been required, the implementation of the Earthing;
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OC6 – Safety Co-ordination Page 82
(d) the Implementing Safety Co-ordinator will ensure the implementation
of the Earthing on his System; and
(e) the Implementing Safety Co-ordinator will confirm to the Requesting
Safety Co-ordinator that Earthing has been established on his System.
8.7 Recording of Safety Precautions
8.7.1 Following confirmation by the Implementing Safety Co-ordinator to the
Requesting Safety Co-ordinator that all of the agreed Safety Precautions have
been established on or relating to the System of the Implementing Safety Coordinator,
the Implementing Safety Co-ordinator will record the details of the
HV Apparatus on which he has been told that Safety From The System is
required and the Safety Precautions established on or relating to the System of
the Implementing Safety Co-ordinator onto parts 1.1 and 1.2 of his RISSP-B.
Where Earthing was not requested (either because Earthing was possible but
was not required or because Earthing was not possible), part 1.2(b) of the
RISSP-B will be completed with the words “not earthed”.
8.7.2 The Implementing Safety Co-ordinator shall then contact the Requesting
Safety Co-ordinator and confirm, by reading out the details entered on parts
1.1 and 1.2 of RISSPB, to the Requesting Safety Co-ordinator, that the Safety
Precautions have been established.
8.7.3 The Requesting Safety Co-ordinator will then complete parts 1.1 and 1.2 of
RISSP-A with the precise details received from the Implementing Safety Coordinator
and then read back all those details to the Implementing Safety Coordinator.
If both confirm that the details entered are the same, the Requesting
Safety Co-ordinator shall issue the RISSP identifying number, as stated on the
RISSP-A, to the Implementing Safety Co-ordinator who shall ensure that the
number, including its prefix and suffix, is correctly entered on the RISSP-B.
8.7.4 The Requesting Safety Co-ordinator and the Implementing Safety Coordinator
shall then respectively complete part 1.3 of RISSP-A and RISSP-B
(which relates to the identity and location of the Implementing Safety Coordinator
and the Requesting Safety Co-ordinator respectively). Each Safety
Co-ordinator shall then complete the issue of the RISSP by signing part 1.3 of
their respective RISSPs and then enter the time and date. Once signed, no
alteration to the RISSP is permitted; the RISSP may only be cancelled.
8.7.5 The Requesting Safety Co-ordinator is then free to authorise work, but not
testing. Where testing is to be carried out, the procedure set out below in
paragraph 9 shall be implemented. The procedure to carry out the work is
entirely an internal matter for the party which the Requesting Safety Coordinator
is representing.
9 Testing
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OC6 – Safety Co-ordination Page 83
9.1 Where the Requesting Safety Co-ordinator wishes to authorise the carrying out of a
test to which the procedures in this paragraph 9 apply he may not do so and the test will
not take place unless and until the following procedures have been followed:
(a) confirmation is obtained from the Implementing Safety Co-ordinator that no
person is working on, or testing, or has been authorised to work on, or test, any
parts of the Systems within the points of Isolation identified on the RISSP form
relating to the test which is proposed to be undertaken (the “original RISSP”),
and the points of Isolation on the Requesting Safety Co-ordinator’s System,
and will not 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) and
thereby the cancellation of the requirements;
(b) all current RISSPs (except for the original RISSP) between the Requesting
Safety Co-ordinator and the Implementing Safety Co-ordinator which relate
to those parts of the Systems between the points of Isolation identified on the
original RISSP and the points of Isolation on the Requesting Safety Coordinator’s
System, have been cancelled in accordance with the procedures set
out in paragraph 9; and
(c) the Implementing Safety Co-ordinator agrees with the Requesting Safety Coordinator
to permit the testing on those parts of the Systems between the points
of Isolation identified in the original RISSP and the points of Isolation on the
Requesting Safety Co-ordinator’s System.
9.2 The Requesting Safety Co-ordinator will inform the Implementing Safety Coordinator
as soon as the test has been completed or cancelled. Where Earthing has
been removed during a test and has not been restored at the original position upon
completion or cancellation of the test, the original RISSP shall be cancelled
immediately in accordance with the procedure set out in paragraph 10.
10 Cancellation
10.1 When the Requesting Safety Co-ordinator decides (having followed all relevant
internal procedures) that Safety Precautions are no longer required, he will contact the
Implementing Safety Co-ordinator and inform him of the RISSP identifying number
(including the prefix and suffix). The Requesting Safety Co-ordinator shall read out to
the Implementing Safety Co-ordinator the details entered on parts 1.1 and 1.2 of his
RISSP-A, and the Implementing Safety Co-ordinator shall confirm that the details
entered on parts 1.1 and 1.2 of the RISSP-B are the same. The Requesting Safety Coordinator
shall then confirm to the Implementing Safety Co-ordinator that the Safety
Precautions are no longer required.
10.2 The Requesting Safety Co-ordinator and the Implementing Safety Co-ordinator
shall then respectively complete part 2.1 of RISSP-A and RISSP-B (which relates to
the identity and location of the Implementing Safety Co-ordinator and the Requesting
Safety Co-ordinator respectively). Each Safety Co-ordinator shall then complete the
cancellation of the RISSP procedure by signing part 2.1 of their respective RISSPs and
then entering the time and date.
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OC6 – Safety Co-ordination Page 84
10.3 Subject as provided in paragraph 10.4, 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 which the Implementing Safety Coordinator
is representing. The only situation in which any Safety Precautions may be
removed without first cancelling the RISSP in accordance with paragraph 10 is when
Earthing is removed in the situation envisaged in paragraph 9.2.
10.4 Where Earthing has been requested neither Safety Co-ordinator shall instruct the
removal of any Isolation forming part of the Safety Precautions until it is confirmed to
each by the other that all Earthing has been removed.
11 Loss of Integrity of Safety Precautions
In any instance when any Safety Precautions may be ineffective for any reason the
relevant Safety Co-ordinator shall without delay inform the other Safety Coordinator(
s) of that being the case and, if requested, of the reasons why.
12 Safety Log
The DNO and each User shall maintain a safety log which shall be a chronological
record of all messages relating to safety co-ordination under this OC6 sent and received
by the Safety Co-ordinator(s). The safety log must be retained for a period of not less
than 3 years.
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OC6 – Safety Co-ordination Page 85
OC6 SAFETY CO-ORDINATION – APPENDIX A
Northern Ireland Electricity
DISTRIBUTION CONTROL CENTRE/USER
RECORD OF INTER-SYSTEM SAFETY PRECAUTIONS (RISSP-A)
(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 to achieve (in so far as it is
possible from that side of the Connection 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]:
1.2 SAFETY PRECAUTIONS ESTABLISHED
(a) ISOLATION
[State the Location(s) at which Isolation has been established. For each Location, identify each point of
Isolation. For each point of Isolation, state the means by which the Isolation has been achieved and whether
immobilised and Locked, Caution Notice affixed or other safety procedures applied, as appropriate.]
(b) EARTHING
[State the Location(s) at which Earthing has been established. For each Location, identify each point of
Earthing. For each point of Earthing, state the means by which the Earthing has been achieved and whether
immobilised and Locked or other safety procedures applied, as appropriate].
1.3 ISSUE
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.
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OC6 – Safety Co-ordination Page 86
Signed ……………………………..(Requesting Safety Co-ordinator)
at ……………………………. (time) on ……………………….(date)
PART 2
2.1 CANCELLATION
I 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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OC6 – Safety Co-ordination Page 87
OC6 SAFETY CO-ORDINATION – APPENDIX B
Northern Ireland Electricity
DISTRIBUTION CONTROL CENTRE/USER
RECORD OF INTER-SYSTEM SAFETY PRECAUTIONS (RISSP-B)
(Implementing 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 to achieve (in so far as it is
possible from that side of the Connection 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]:
1.2 SAFETY PRECAUTIONS ESTABLISHED
(a) ISOLATION
[State the Location(s) at which Isolation has been established. For each Location, identify each point of
Isolation. For each point of Isolation, state the means by which the Isolation has been achieved and whether
immobilised and Locked, Caution Notice affixed or other safety procedures applied, as appropriate.]
(b) EARTHING
[State the Location(s) at which Earthing has been established. For each Location, identify each point of
Earthing. For each point of Earthing, state the means by which the Earthing has been achieved and whether
immobilised and Locked or other safety procedures applied, as appropriate].
1.3 ISSUE
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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OC6 – Safety Co-ordination Page 88
PART 2
2.1 CANCELLATION
I have received confirmation from _________________________________ (name of the Requesting Safety Coordinator)
at _______________________________ (location) that the Safety Precautions set out in paragraph
1.2 are no longer required and accordingly the RISSP is cancelled.
Signed ……………………………(Implementing Safety Co-ordinator)
at …………………….(time) on ……………………..(Date)
(Note: This form to be a different colour from RISSP-A)
Distribution Code 1 May 2010
OC7 – Contingency Planning Page 89
Operating Code 7 – Contingency Planning
1 Introduction
1.1 Operating Code No. 7 (“OC7”) covers the following:-
(a) The DNO’s role in the implementation of recovery procedures in the event of a
Total Shutdown or Partial Shutdown; and
(b) the procedure to be followed when the Distribution Service Centre is
incapacitated for any reason.
It recognises that the main role in the event of any of those situations arising will be
undertaken by the TSO, and that under the Grid Code and the related emergency
procedures the DNO will principally be acting in accordance with the instructions of
the TSO.
1.2 It should be noted that, under Article 58 of the Order, the Department may give
directions to the DNO, the TSO and/or any Generator and any Supplier for the
purpose of, “mitigating the effects of any civil emergency which may occur” (i.e. for
the purposes of planning for dealing with a civil emergency); a civil emergency is
defined in the Order as “any natural disaster or other emergency which, in the opinion
of the Department, is or may be likely to disrupt electricity supplies”.
1.3 Additionally, under the Energy Act 1976, the Secretary of State has powers to make
orders and give directions controlling the production, supply, acquisition or use of
electricity, where an Order in Council under Section 3 is in force declaring that there is
an actual or imminent emergency affecting electricity supplies. In the event that any
such directions are given or orders made under the Energy Act 1976, the provisions of
the Distribution Code will be suspended insofar as they are inconsistent with them.
2 Objective
The overall objectives of OC7 are:
(a) to outline and enable co-ordination between the DNO and Users in the situation
where the TSO under the Grid Code is seeking to recover from a Total or
Partial Shutdown to achieve, as far as possible, restoration and Re-
Synchronisation of the Total System and to enable Demand once again to be
satisfied in the shortest possible time; and
(b) to ensure that the NI System can continue to operate in the event that the
Distribution Service Centre is incapacitated for any reason.
3 Scope
3.1 OC7 applies to the DNO and to Users. Users in this OC7 means:
(a) Generators;
(b) Suppliers; and
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OC7 – Contingency Planning Page 90
(c) Demand Customers in respect of Connection Sites with a Demand of 1MW
and above.
4 Black Start Procedure
4.1 Total Shutdown
When a “Total Shutdown” occurs, namely where all generation has ceased and there is
no electricity supply across any Interconnectors and the Inter-jurisdictional Tie Lines
between Northern Ireland and the Republic of Ireland resulting in the Total System
having shutdown, it is not possible for the Total System to begin to function again
without the TSO’s directions relating to a Black Start.
4.2 Partial Shutdown
When a “Partial Shutdown” occurs, namely a situation which is 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 to that part of the Total System and, therefore, that
part of the Total System is shutdown, it is not possible for that part of the Total
System to begin to function again without the TSO directions relating to a Black Start.
4.3 Licence Standards
During a Total Shutdown or Partial Shutdown and during the period leading up to
such shutdowns and the subsequent recovery, the Licence Standards may not be met
and the whole or any part of the Total System may be operated outside normal voltage
and/or Frequency.
4.4 Black Start situation
In the event of a Total Shutdown or Partial Shutdown, the DNO will inform Users
which in the DNO’s opinion need to be informed that a Total Shutdown or, as the case
may be, a Partial Shutdown, exists and that it has been notified by the TSO that the
TSO intends to implement a Black Start.
4.5 Black Start
4.5.1 The procedure necessary for a recovery from a Total Shutdown or Partial
Shutdown is a “Black Start”. The procedure for a Partial Shutdown is the
same as that for a Total Shutdown except that it applies only to a part of the
Total System. It should be noted that a Partial Shutdown may affect parts of
the Total System which are not themselves shutdown.
4.5.2 The overall strategy for recovery from a Total Shutdown or Partial Shutdown
will, in general, include the overlapping phases of establishment by the TSO of
isolated Power Stations, together with complementary local Demand, termed
“Power Islands”, step by step integration of these Power Islands into larger subsystems
and, eventually, complete re-establishment of the Total System.
4.5.3 The TSO will, in accordance with the Grid Code, be instructing the DNO to
assist in relation to this process and under this OC7 the DNO may contact Users
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OC7 – Contingency Planning Page 91
to discuss and instruct Users in relation to the role they are to play as part of the
recovery.
4.5.4 The conclusion of the Black Start and the time of the return to normal
operation of the Total System will be determined by the TSO which shall
inform the DNO, in accordance with the terms of the Grid Code. The DNO
will then inform Users which in the DNO’s opinion need to be informed, that
the Black Start situation no longer exists and that normal operation of the Total
System has begun.
5 Loss of the Distribution Service Centre
If the event of the temporary loss of the Distribution Service Centre the DNO will
have arrangements in place whereby the DNO may transfer the functions of the
Distribution Service Centre to an alternative control facility whereupon the DNO will
inform Users of the communications details for the new location.
Distribution Code 1 May 2010
OC8 – Numbering and Nomenclature of Plant and Apparatus at Connection Sites Page 92
Operating Code 8 – Numbering and Nomenclature of Plant and Apparatus at Connection
Sites
1 Introduction
1.1 Operating Code No. 8 (“OC8”) sets out the responsibilities and procedures for
determining and notifying the DNO and Users of the numbering and/or nomenclature
of the other’s Plant and/or Apparatus at Connection Sites. For clarification,
nomenclature shall include the selection of Substation names.
1.2 The numbering and/or nomenclature of Plant and/or Apparatus is to be included in an
Ownership Diagram prepared for each Connection Site as provided in the
Connection Conditions.
2 Objectives
The prime objective embodied in this OC8 is to ensure that at any Connection Site
items of Plant and/or Apparatus has numbering and/or nomenclature that, so far as
possible, has been mutually agreed and that has been notified between the DNO and
Users to ensure, so far as is reasonably practicable, the safe and effective operation of
the Distribution System and the User System by minimising the risk of error in
identifying Plant and/or Apparatus.
3 Scope
3.1 OC8 applies to the DNO and to Users. Users in this OC8, means:
(a) Generators in respect of their Generating Units connected to the Distribution
System at 33kV; and
(b) Demand Customers in respect of their 33kV Connection Sites; and
(c) those further Generators and Demand Customers in respect of their HV
Connection Sites as notified by the DNO in writing.
4 Procedure
4.1 General requirement
4.1.1 Plant and/or Apparatus of a User at a Connection Site shall have numbering
and/or nomenclature which cannot be confused with that of the DNO’s Plant
and Apparatus at that Connection Site.
4.1.2 In furtherance of the general requirement set out in paragraph 4.1.1 above, no
User will install, or permit the installation of, any Plant and/or Apparatus
which has numbering and/or nomenclature which could be confused with that of
the DNO which is either already on that Connection Site or which the DNO has
notified the User will be installed on that Connection Site. The procedure for
determining the applicable numbering and nomenclature for new and existing
Connection Sites is set out in paragraphs 4.2.1 and 4.2.2 respectively.
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OC8 – Numbering and Nomenclature of Plant and Apparatus at Connection Sites Page 93
4.2 Plant and Apparatus
4.2.1 New Connection Sites
When a User intends to install or the DNO intends to install Plant and/or
Apparatus as part of the construction and commissioning of a new Connection
Site, the proposed numbering and/or nomenclature shall be notified as part of
the production of the Ownership Diagram in accordance with the provisions of
the Connection Conditions. The principles to apply to determine whether that
proposed numbering and/or nomenclature is acceptable will be those set out in
this OC8 (including, for the avoidance of doubt, the provisions of paragraph
4.2.2(e)).
4.2.2 Existing Connection Sites
(a) When a User intends to install or the DNO intends to install Plant
and/or Apparatus at an existing Connection Site the proposed
numbering and/or nomenclature to be adopted for the Plant and/or
Apparatus shall be notified to the other.
(b) The notification shall be made in writing to the other and will consist of
a revised Ownership Diagram incorporating the proposed new Plant
and/or Apparatus to be installed and its proposed numbering and/or
nomenclature.
(c) The notification shall be made at least six months (or such shorter period
as the DNO or the User, as the case may be, may agree) prior to the
proposed installation of the Plant and/or Apparatus.
(d) The recipient of the notification shall respond in writing within one
month of the receipt of the notification confirming receipt and
confirming whether the proposed numbering and/or nomenclature is
acceptable or, if not, what would be acceptable.
(e) In the event that agreement cannot be reached between the DNO and the
User, the DNO acting reasonably, shall have the right to determine the
numbering and nomenclature to be applied at the Connection Site.
4.3 Changes to existing Plant and Apparatus
Where there needs to be a change of the existing numbering or nomenclature of any of
the DNO’s Plant and/or Apparatus at a Connection Site or a User needs to change
the existing numbering or nomenclature of any of its Plant and/or Apparatus at a
Connection Site, the provisions of paragraph 4.2.2 shall apply, with any amendments
necessary to reflect that only a change is being made.
4.4 Clear labelling
The DNO shall be responsible for ensuring the provision, erection and maintenance of
clear and unambiguous labelling showing the numbering and nomenclature of the
DNO’s Plant and/or Apparatus at Connection Sites and each User shall be
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OC8 – Numbering and Nomenclature of Plant and Apparatus at Connection Sites Page 94
responsible for the provision, erection and maintenance of clear and unambiguous
labelling showing the numbering and nomenclature of the User’s Plant and/or
Apparatus at Connection Sites.
Distribution Code 1 May 2010
OC9 – System Tests Page 95
Operating Code 9 – System Tests
1 Introduction
1.1 Operating Code No. 9 (“OC9”) relates to the following types of test (all of which are
referred to as “System Tests”):-
(a) tests to be carried out by a User or the DNO which involve or may involve
simulating conditions or the controlled application of irregular, unusual or
extreme conditions on the User’s System or the Distribution System (as the case
may be) which may have a material effect on the Total System, beyond the
User’s System or the Distribution System (as the case may be);
(b) tests to be carried out by the TSO or a user under the Grid Code which involve
or may involve simulating conditions or the controlled application of irregular,
unusual or extreme conditions on the NI System or that user’s system (as the case
may be) which may have a material effect on the Distribution System and the
System of a User under this Distribution Code, and which the DNO therefore
decides, in its view, should be raised as a connected system test (a “Connected
System Test”) under this OC9 to ensure that Users under this Distribution Code
are included within the consideration of the system test being proposed under the
Grid Code; and
(c) Commissioning/Acceptance Tests of Plant and Apparatus to be carried out by a
User or the DNO which involve or may involve the application of irregular,
unusual or extreme conditions and which may have a material effect on the Total
System, beyond the User’s System or the Distribution System (as the case may
be).
1.2 OC9 only deals with the responsibilities and procedures for arranging and carrying out
tests which have (or may have) a material effect on the Systems of both the DNO and
Users. Accordingly, where a test proposed by a User will not have a material effect on
the Distribution System or where a test proposed by the DNO will not have a material
effect on a User System, such test will not fall within this OC9 and OC9 shall not apply
to it.
1.3 OC9 does not cover Commissioning/Acceptance Tests of a User’s Plant and
Apparatus which will have no material effect on the Distribution System beyond the
User’s System; such tests will be undertaken solely pursuant to paragraph 10 and 11 in
the Connection Conditions. Neither does it cover the type of tests which are dealt with
in OC10, “Testing, Monitoring and Investigation”.
1.4 The Grid Code contains provisions relating to system tests under the Grid Code, which
will be initiated by the TSO or users under the Grid Code. The DNO is a user under the
Grid Code and certain Users under the Distribution Code will also be users under the
Grid Code. A system test under the Grid Code may therefore involve, and affect, the
Distribution System, and the TSO is required under the Grid Code to obtain agreement
from all affected Grid Code users. In that instance if the DNO was a user so affected
under the Grid Code, the DNO may decide that it should initiate a Connected System
Test under this OC9 in order to ensure that Users are involved in the Grid Code system
Distribution Code 1 May 2010
OC9 – System Tests Page 96
test.
2 Objective
2.1 The overall objectives of OC9 are:-
(a) to ensure, so far as possible, that tests proposed to be carried out:
(i) by a User which may have a material effect on the Total System or any
part of the Total System (in addition to that User’s System) including the
Distribution System;
(ii) by the DNO which may have a material effect on a Users’ System (in
addition to the Distribution System); or
(iii) under the Grid Code in certain circumstances;
do not threaten the safety of personnel or threaten to damage Plant and/or
Apparatus and cause minimum detriment to the DNO and Users. These tests will
not affect the Transmission System and therefore the reference to Total System
above excludes the Transmission System; and
(b) to set out the procedures to be followed for establishing and where appropriate
reporting such tests and to set out guidelines for which tests need to be notified to
the DNO prior to the test being carried out.
3 Scope
3.1 OC9 applies to the DNO and to Users which, in this OC9 means:
(a) Generators, and
(b) Demand Customers.
4 Procedure
4.1 Proposal Notice
4.1.1 The level of Demand on the Distribution System varies substantially according
to the time of day and time of year and, consequently, certain System Tests
which may have a significant impact on the Distribution System (for example,
tests of the Full Load capability of a Generating Unit over a period of several
hours) can only be undertaken at certain times of the day and year. Other System
Tests, for example, those involving substantial MVAr generation, may also be
subject to timing constraints. It therefore follows that notice of System Tests
should be given as far in advance of the date on which they are proposed to be
carried out as reasonably practicable.
4.1.2 Where a User wishes to carry out a System Test it shall submit a notice (a
“Proposal Notice”) to the DNO as far in advance as is reasonably practicable of
the date it would like to undertake the proposed System Test. In the event that a
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OC9 – System Tests Page 97
User submits to the DNO a programme for proposed
Commissioning/Acceptance Testing pursuant to paragraph 10.1.4 in the
Connection Conditions which the DNO considers may involve the application of
irregular, unusual or extreme conditions and which may have a material effect on
the Distribution System, beyond the User’s System, such programme shall be
treated as a Proposal Notice for the purposes of this OC9.
4.1.3 The Proposal Notice shall be in writing, or in such other form as the DNO and
the relevant User may otherwise agree (such agreement not to be unreasonably
withheld), and shall contain details of the nature and purpose of the proposed
System Test and shall indicate the identity and situation of the Plant and/or
Apparatus involved. In the case of a System Test involving a CDGU, the User
shall state in the Proposal Notice the level of Availability and the values for
Technical Parameters which will be declared for the CDGU for the period of the
test in accordance with SDC1 of the Grid Code and shall also include details of
the planned operation by the User as part of the test. In the case of a Generating
Plant, it will also confirm that the User will be arranging with the TSO for a
relevant Dispatch Instruction to be issued to it for the purposes of the test. For the
purposes of this paragraph 4.1, “Dispatch Instructions”, “Availability” and
“Technical Parameters” shall have the meaning given to such terms in the Grid
Code.
4.1.4 If the DNO is reasonably of the view that the information set out in the Proposal
Notice is insufficient, it will contact the person who submitted the Proposal
Notice (the “Test Proposer”) as soon as reasonably practicable, with a written
request for further information. The DNO shall not be required to do anything
under this OC9 until it is satisfied with the details supplied in the Proposal Notice
or pursuant to a request for further information.
4.1.5 If the DNO wishes to undertake a System Test or a Connected System Test, the
DNO shall be deemed to have received a Proposal Notice for that System Test.
4.1.6 The DNO will use all reasonable endeavours to accommodate requests for System
Tests but has absolute discretion as to the timing of such tests (which discretion
will be exercised reasonably consistently with previous practice) to ensure the
proper operation of the Distribution System and so as to ensure that the Licence
Standards are not breached.
4.1.7 Without prejudice to the general description of the types of System Tests which
have to be dealt with under this OC9, as set out in paragraph 1.1 above, each
Generator must submit a Proposal Notice to the DNO if it proposes to carry out
any of the following tests, each of which is therefore a System Test:-
(a) VAr limiter tests; and
(b) Load rejection tests.
4.2 Establishment of Test Panel
(a) Using the information supplied (or deemed to have been supplied) to it under
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OC9 – System Tests Page 98
paragraph 4.1, the DNO will determine, in its reasonable estimation, which
Users, other than the Test Proposer, may be materially affected by the proposed
System Test and will notify such Users accordingly.
(b) The DNO will then determine, in its reasonable opinion, whether a Test Panel is
required taking into account the degree of severity of its possible effect on the
Systems of the DNO and Users. A Test Panel will not generally be needed for a
routine test and, since the majority of System Tests are routine, the establishment
of a Test Panel will be the exception rather than the rule. If the DNO, in its
reasonable discretion, decides that a Test Panel is necessary, the provisions set
out in the Appendix to this OC9 will apply.
4.3 The DNO Supervision
(a) If the DNO determines that no Test Panel is required, it will determine, acting
reasonably, whether and, where appropriate, when the proposed System Test can
take place and it will consider:-
(i) the details of the nature, technical reasons for and timing of the proposed
System Test and other matters set out in the Proposal Notice (together
with any further information requested by the DNO under OC9.4.1.4);
(ii) the economic, operational and risk implications of the proposed System
Test; and
(iii) the possibility of combining the proposed System Test with any other tests
and with Plant and/or Apparatus Outages which arise pursuant to the
Outage Planning requirements of the DNO and Users.
If the DNO determines that the proposed System Test cannot take place, it will,
insofar as it is able to do so without breaching any obligations regarding
confidentiality contained either in the Licence held by the DNO or in any
agreement, notify the Test Proposer of the reasons for such decision in such
degree of detail as the DNO considers reasonable in the circumstances.
(b) Users identified by the DNO under paragraph 4.2.1 (and the Test Proposer) shall
be obliged to supply the DNO, upon written request, with such details as the
DNO reasonably requires in order to consider the proposed System Test.
(c) The DNO will consult with each User identified by it under paragraph 4.2.1
regarding the proposed System Test including, in particular, the effects which
such test is likely to have on such User’s System.
4.4 The DNO Test Programme
(a) As soon as practicable the DNO shall, if it approves of the proposed System Test
taking place (of which it will notify the Test Proposer), taking into account the
factors specified in paragraph 4.3.1, prepare a programme (the “Test
Programme”), in such detail as the DNO considers, in its reasonable opinion, to
be appropriate for the test, which will include:-
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(a) the procedure to be adopted for carrying out the System Test, including
the switching sequence and proposed timings of the switching sequence;
(b) the manner in which the System Test is to be monitored;
(c) a list of those members of staff to be involved in carrying out the System
Test, including those who will be responsible for site safety; and
(d) such other matters as the DNO considers appropriate including (without
limitation) matters suggested by Users identified by the DNO pursuant to
paragraph 4.2.1.
(b) The DNO, the Test Proposer and each User identified by the DNO under
paragraph 4.2.1 will determine by agreement the basis on which the costs of the
System Test (including unanticipated costs, for example, costs arising from
modifications etc) shall be borne as between the affected parties (the general
principle being that the Test Proposer will bear such costs). If agreement cannot
be reached (each party having acted in good faith), the System Test will be
cancelled.
(c) Without prejudice to the provisions of paragraph 4.1, the DNO shall be entitled to
require the proposed System Test to be modified, delayed or cancelled if, in its
reasonable opinion, it considers that such test would impose unacceptable effects
on the Distribution System or any User System.
(d) If the DNO requires the proposed System Test to be cancelled or if it requires
such test to be delayed or modified but the Test Proposer considers that such
delay or modification is not possible, the proposed System Test shall not take
place.
(e) The Test Programme will, subject to paragraph 4.4.6, bind the Test Proposer to
act in accordance with the provisions of the Test Programme in relation to the
proposed System Test.
(f) Any problems with the proposed System Test perceived by the Test Proposer or
any affected User or the DNO which arise or are anticipated after the issue of the
Test Programme and prior to the day of the proposed System Test must be
notified by the Test Proposer or affected User or the DNO (as the case may be)
to the others as soon as possible in writing. If, in any such case, the DNO decides
that these anticipated problems merit an amendment to, or postponement of, the
System Test, it shall notify the Test Proposer and affected Users accordingly.
(g) If, on the day of the proposed System Test, operating conditions on the
Distribution System are such that any of the DNO, the Test Proposer or an
affected User wishes to delay or cancel the start or continuance of the System
Test, they shall immediately inform the others of this decision and the reasons for
it. The DNO shall then postpone or cancel, as the case may be, the System Test
and another suitable time and date shall be arranged in accordance with this
paragraph 4.4.
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Appendix
1 Test Panel supervision
1.1 If the DNO determines pursuant to paragraph 4.2.2 that a Test Panel is required, it will
appoint a representative to co-ordinate the System Test (the “Test Co-ordinator”) as
soon as reasonably practicable after it has, or is deemed to have, received a Proposal
Notice and in any event prior to the distribution of the Preliminary Notice referred to
below. The Test Co-ordinator shall act as Chairman of the Test Panel and shall be a full
member of the Test Panel.
1.2 The DNO will notify all Users identified by it under paragraph 4.2.1 of the proposed
System Test by a notice in writing (a “Preliminary Notice”) and will send a copy of the
Preliminary Notice to the Test Proposer. The Preliminary Notice will contain:
(a) the details of the nature and purpose of the proposed System Test, the identity
and situation of the Plant and/or Apparatus involved, the identities of the Users
identified by the DNO under paragraph 4.2.1 and the identity of the Test
Proposer;
(b) an invitation to nominate within one month a suitably qualified representative (or
representatives if the Test Co-ordinator considers that it is appropriate for a
particular User to nominate more than one representative) to be a member of the
Test Panel for the proposed System Test; and
(c) the name of the DNO representative whom the DNO has appointed as the Test
Co-ordinator and who will be a member of the Test Panel for the proposed
System Test together with the names of any other representatives whom the DNO
has nominated to be members of the Test Panel.
1.3 The Preliminary Notice will be sent within one month of the later of either the receipt by
the DNO of the Proposal Notice, or of the receipt of any further information requested
by the DNO under paragraph 4.1.3. Where the DNO is the proposer of the System Test,
the Preliminary Notice will be sent within one month of the proposed System Test being
fully formulated.
1.4 Replies to the invitation in the Preliminary Notice to nominate a representative to be a
member of the Test Panel must be received by the DNO within one month of the date on
which the Preliminary Notice was sent to the User by the DNO. Any User which has
not replied within that period will not be entitled to be represented on the Test Panel. If
the Test Proposer does not reply within that period, the proposed System Test will not
take place and the DNO will notify all Users identified by it under paragraph 4.2.1
accordingly.
1.5 The DNO will, as soon as possible after the expiry of that one month period, appoint the
nominated persons to the Test Panel and notify all Users identified by it under paragraph
4.2.1 and the Test Proposer, of the composition of the Test Panel.
2 Test Panel
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2.1 A meeting of the Test Panel will take place as soon as possible after the DNO has
notified all Users identified by it under paragraph 4.2.1 and the Test Proposer of the
composition of the Test Panel, and in any event within one month of the appointment of
the Test Panel.
2.2 The Test Panel shall consider:
(a) the details of the nature, technical reasons for and timing of the proposed System
Test and other matters set out in the Proposal Notice (together with any further
information requested by the DNO under paragraph 4.1.3);
(b) the economic, operational and risk implications of the proposed System Test;
(c) the possibility of combining the proposed System Test with any other tests and
with Plant and/or Apparatus Outages which arise pursuant to the Operational
Planning requirements of the DNO and Users; and
(d) whether, at the conclusion of the System Test, the Test Proposer should be
required to prepare a written report on the System Test (a “Final Report”) in
accordance with paragraph 4 in the Appendix and, if so, the period within which
the Final Report must be prepared.
2.3 Users identified by the DNO under OC9.4.2.1, the Test Proposer (whether or not they
are represented on the Test Panel) and the DNO shall be obliged to supply the Test
Panel, upon written request, with such details as the Test Panel reasonably requires in
order to consider the proposed System Test.
2.4 The Test Panel shall be convened by the Test Co-ordinator as often as he considers
necessary to conduct its business.
3 Test Panel Test Programme
3.1 As soon as practicable after its first meeting, the Test Panel shall, taking into account the
factors specified in paragraph A.2.2 in the Appendix, prepare a programme (the “Test
Programme”) which will include:-
(a) the procedure to be adopted for carrying out the System Test, including the
switching sequence and proposed timings of the switching sequence;
(b) the manner in which the System Test is to be monitored;
(c) a list of those members of staff to be involved in carrying out the System Test,
including those who will be responsible for site safety; and
(d) such other matters as the Test Panel considers to be appropriate.
3.2 The Test Panel shall also determine the basis on which the costs of the System Test
(including unanticipated costs) shall be borne as between the affected parties (the general
principle being that the Test Proposer will bear such costs). If the Test Panel cannot
agree on this (each party having acted in good faith), the System Test will be cancelled.
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3.3 The Test Co-ordinator shall be entitled to require the proposed System Test to be
modified, delayed or cancelled if, in his reasonable opinion, he considers that such test
would impose unacceptable effects on the Distribution System or on any User System.
3.4 If the Test Co-ordinator requires the proposed System Test to be cancelled or if he
requires such test to be delayed or modified but the Test Proposer considers that such
delay or modification is not possible, the proposed System Test shall not take place and
the Test Panel will disband automatically.
3.5 If the Test Co-ordinator requires the proposed System Test to be modified or delayed
and such modification or delay is possible, the Test Panel shall, as soon as practicable,
revise the Test Programme accordingly.
3.6 The Test Programme will, subject to paragraph 3.7 in this Appendix, bind all recipients
to act in accordance with the provisions of the Test Programme in relation to the
proposed System Test.
3.7 Any problems with the proposed System Test which arise or are anticipated after the
issue of the Test Programme and prior to the day of the proposed System Test must be
notified to the Test Co-ordinator as soon as possible in writing. If the Test Coordinator
decides that these anticipated problems merit an amendment to, or
postponement of, the System Test, he shall notify the Test Proposer (unless the test was
proposed by the DNO) and each User identified by the DNO under paragraph 4.2.1
accordingly.
3.8 If, on the day of the proposed System Test, operating conditions on the Distribution
System are such that any party involved in the proposed System Test wishes to delay or
cancel the start or continuance of the System Test, they shall immediately inform the
Test Co-ordinator of this decision and the reasons for it. The Test Co-ordinator shall
then postpone or cancel, as the case may be, the System Test and shall, if possible, agree
with the Test Proposer (unless the test was proposed by the DNO) and all Users
identified by the DNO under paragraph 4.2.1 another suitable time and date. If he cannot
reach such agreement, the Test Co-ordinator shall reconvene the Test Panel as soon as
practicable, which will endeavour to arrange another suitable time and date for the
System Test, in which case the relevant provisions of this OC9 shall apply.
4 Connected System Tests
4.1 In the case of a Connected System Test, the timings and process outlined in this
Appendix may be amended by the DNO to co-ordinate with the process being undertaken
under the Grid Code.
5 Test Panel Final Report
5.1 At the conclusion of the System Test, the Test Proposer shall, if so decided by the Test
Panel pursuant to paragraph 2.2(d) in the Appendix, prepare a Final Report for
submission to the DNO and the other members of the Test Panel. The Final Report
shall be submitted within the period agreed by the Test Panel pursuant to paragraph
2.2(d).
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5.2 The Test Proposer may omit from the Final Report matters which, in its reasonable
opinion, are confidential to it and the Final Report shall not be submitted to any person
who is not a member of the Test Panel unless the Test Panel, having considered the
confidentiality issues arising, shall have unanimously approved such submission.
5.3 The Final Report shall include a description of the Plant and/or Apparatus tested and
a description of the System Test carried out, together with the results and, where
appropriate, the conclusions and recommendations of the Test Panel.
5.4 When the Final Report has been prepared and submitted in accordance with paragraph
4.1 in this Appendix, the Test Panel will disband automatically. If a Final Report is
not required by the Test Panel then it will disband automatically upon the conclusion of
the System Test.
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Operating Code 10 – Testing, Monitoring and Investigation
1 Introduction
1.1 Operating Code No. 10 (“OC10”) specifies the procedures to be followed by the DNO
in carrying out:
(a) Monitoring of the compliance of Generating Units and Demand Customers’
Plant and/or Apparatus with the Connection Conditions;
(b) Testing:-
(i) in certain circumstances, (whether by means of a formal test or
verification by inspection) to ascertain whether the Connection
Conditions are being complied with in respect of Generating Units and
Demand Customer’s Plant and/or Apparatus; and
(ii) at the request of a User, in certain circumstances; and
(c) Investigations in relation to equipment and operational procedures at Power
Stations and other User Sites.
1.2 It should be noted that Testing and Monitoring under this OC10 are two different
procedures with, in general terms, DNO representatives being present at the Power
Station or User Site for a Test, but not for Monitoring.
2 Objectives
2.1 The objectives of OC10 are to establish whether Generating Units and Demand
Customers’ Plant and/or Apparatus comply with the Connection Conditions.
3 Scope
3.1 OC10 applies to the DNO and to Users. Users in this OC10 means:
(a) Generators; and
(b) Demand Customers in respect of their Connection Sites with a Demand of
1MW and above.
4 Procedure for Monitoring
4.1 Monitoring may be carried out at any time by the DNO and involves the analysis of
the output of Monitoring equipment (as required or permitted under the Connection
Conditions and/or the Connection Agreement) to show the output and/or performance
of a User’s Equipment in order to see whether the User’s Equipment is meeting the
requirements of the Connection Conditions. The output from such Monitoring
equipment installed may, amongst other uses, be used to Monitor the performance of
User’s Equipment in the event of variations in NI System Frequency.
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4.2 In determining whether a User’s equipment is meeting the requirements of the
Connection Conditions the DNO shall in each case give due regard to operating
conditions on the Distribution System.
4.3 If a User’s Equipment is not meeting the requirements of the Connection Conditions,
the DNO will, submit a Monitoring Notice to the User which will identify the
Connection Conditions requirements which have been Monitored and which have not
been met.
4.4 Consequences of Monitoring
4.4.1 The User will provide the DNO as soon as possible with an explanation of the
reasons for the failure and the actions it is proposing to undertake to enable its
equipment to meet the requirements of the Connection Conditions which it has
not met within a reasonable period.
4.4.2 The DNO and the User will then discuss the action which the user proposes to
take and will seek to reach agreement on any short term operational matters
necessary to protect the Distribution System and the Systems of other Users
and the time by which the requirements will be met. In the absence of
agreement between the User and the DNO on this, the DNO shall refer the
Distribution Code non-compliance to the Authority.
4.4.3 Once the User confirms to the DNO, in the agreed timescale, that its equipment
meets the relevant Connection Conditions requirements, the DNO may verify
that either by further Monitoring or by undertaking a Test under this OC10.
5 Procedure for Testing
5.1 In circumstances where the DNO reasonably considers that, in relation to User’s
Equipment, a User might be failing to comply with the Connection Conditions (or
where it wishes to verify that the equipment now meets the requirements where
Monitoring or a previous test has demonstrated non-compliance) the DNO may, upon
giving reasonable notice identifying the requirement concerned, send representatives to
the relevant User Site in order to verify by Testing or inspection (in the case of
Testing, conducted by the User) whether in relation to the item of User’s Equipment,
the Connection Conditions requirements are being met.
5.2 Each User must allow the DNO representatives access to all relevant parts of its User
Site for the purposes of this OC10.
5.3 The procedure for the Test, and the criteria for passing the Test, will, if not agreed
between the DNO and the User, be as determined by the DNO acting reasonably and as
notified to the User at the time and the User will comply with all reasonable
instructions of the DNO in carrying out the Test.
5.4 In determining whether the item of User’s Equipment, as the case may be, has passed
a Test, due regard will be given by the DNO to operating conditions on the NI System.
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5.5 If in relation to the item of User’s Equipment the User fails the Test then: it must
provide the DNO with a written report specifying in reasonable detail the reasons for
the failure, such report to be submitted within 5 Business Days of the Test. The User
must then within five further Business Days submit in writing to the DNO for approval
the date by which the User proposes to have brought the equipment to a condition
where it would meet the requirements of the Connection Conditions. The DNO may
either accept this period, or suggest a shorter period. In the absence of agreement
between the User and the DNO on this, the DNO shall refer the Distribution Code
non-compliance to the Authority.
5.6 Once the User confirms to the DNO, in the agreed timescale, that its equipment meets
the relevant Connection Conditions requirements, the DNO may verify that either by
Monitoring or by undertaking a further Test under this OC10.
6 Investigations
6.1 The DNO may, upon giving reasonable notice (in any event not less than 2 Business
Days), send representatives to a Power Station or User Site in order to investigate any
equipment or operational procedure.
6.2 An Investigation may take place only for the purposes of enabling the DNO to fulfil its
obligations relating to the operation of the Distribution System (and where in the
reasonable opinion of the DNO in the absence of an Investigation it would be unable
properly to fulfil such obligations).
6.3 An Investigation shall not take place during or less than 2 days before or after a Test in
respect of Plant or equipment at the relevant Power Station or User Site.
6.4 The DNO’s notice under paragraph 6.1 shall specify:
(a) the nature and purpose of the Investigation and the reasons therefor;
(b) the equipment or operational procedure subject to the Investigation; and
(c) the procedure (as reasonably determined by the DNO) for the Investigation.
6.5 The scope of an Investigation and the information and parts of the Power Station or
User Site to which the DNO shall be entitled to access shall be limited to that required
for the purposes of the Investigation as specified in the DNO’s notice under paragraph
6.4.
6.6 The User shall comply with the reasonable requests of the DNO in carrying out the
Investigation, and allow the DNO representative access to all relevant parts of the
Power Station or User Site to conduct the Investigation.
6.7 An Investigation shall not of itself result in consequences for the User under the
Distribution Code or Connection Agreement.
6.8 These provisions shall be without prejudice to DNO’s rights of access under any other
document or agreement.
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7 Testing at the request of a User
7.1 A User shall, subject to paragraph 7.2, be entitled, by notice in writing setting out the
desired procedure (or, if the DNO acting reasonably so agrees, taking into account the
nature of the test being requested, by oral request specifying the desired procedure,
such oral request to be confirmed in writing as soon as reasonably practicable
thereafter), to request the DNO to assist it in carrying out a test on any of its Plant
and/or Apparatus as such User, acting reasonably in accordance with Prudent
Operating Practice, may request.
7.2 The DNO shall be entitled to refuse to conduct any test requested under paragraph 7.1
(or refuse to conduct it in accordance with the procedure or at the time requested) if, in
the DNO’s reasonable opinion, it is unsafe for the Distribution System to conduct such
a test or if it is otherwise not practicable to do so (or to do so in accordance with the
procedure or at the time requested) for Distribution System or any other reasons,
including if all reasonable costs and expenses of the DNO are not, in the DNO’s
reasonable view, adequately covered by the User. The DNO may only continue to
refuse to conduct the test (or to conduct it in accordance with the procedure) for so long
as these reasons continue.
7.3 If the DNO refuses to conduct the test, either at all or in accordance with the procedure
or at the time requested, the DNO and the User may discuss an alternative form of test
or procedure for conducting the test or timing of the test to see whether agreement can
be reached.
7.4 If the DNO agrees to the test taking place, to the procedure for conducting the test and
to the time of the test, either in response to the original request or following the
discussion referred to in paragraph 7.3, it will notify the User accordingly.
7.5 If the DNO does not (following the discussion referred to in paragraph 7.3) agree to the
test taking place, then it will not take place, provided that as indicated in paragraph 7.2
above, the DNO may only continue to refuse to conduct the test for so long as the
reasons set out in that paragraph continue to apply.
7.6 If the DNO does not (following such discussion) agree to the procedure for conducting
the test, then if the test is to go ahead, the DNO’s requirements relating to the
procedure will prevail, unless the reasons set out in paragraph 7.2 above no longer
continue.
7.7 If the DNO does not (following such discussion) agree to the timing of the test, then if
the test is to go ahead, the DNO’s requirements relating to timing will prevail.
7.8 The DNO may then, in accordance with the agreed (or otherwise settled) procedure and
timing and if agreed by the User, send representatives to the User Site in order to
witness the test.
7.9 The User must, if agreed under paragraph 7.8 above, allow the DNO witnesses access
to all relevant parts of its User Site in order to witness such a test.
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7.10 The DNO shall take all reasonable steps to ensure that any representatives that it sends
to the User Site pursuant to paragraph 7.9 above comply at all times with all relevant
safety requirements of the User of which they are made aware and with all reasonable
directions of the User and (but subject to paragraph 7.8) any reasonable restrictions on
access whilst at the User Site in question.
8 Commissioning/Acceptance Testing
1.1 The Connection Conditions reflect the Commissioning/Acceptance Testing which
will be required under each Connection Agreement for User’s Equipment prior to
being certified as acceptable to be and remain connected (or to be reconnected) to the
Distribution System and for modifications to existing User’s Equipment.
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Distribution Metering Code
Table of Contents
Page
1 Introduction ………………………………………………………………………….110
2 Objectives…………………………………………………………………………….111
3 Scope …………………………………………………………………………………112
4 Procedure …………………………………………………………………………….112
5 Ownership and Meter Responsible Person………………………………………….112
6 Data Collection ………………………………………………………………………113
7 Accuracy……………………………………………………………………………..114
8 Calibration……………………………………………………………………………114
9 Proper Order, Testing, Sealing and Reading ……………………………………….114
10 Access ………………………………………………………………………………..119
11 Disputes ………………………………………………………………………………120
12 Information …………………………………………………………………………..122
13 Ownership of Metering Data ………………………………………………………..122
14 New Connection Registration and Change of Supplier …………………………….123
15 Notices ……………………………………………………………………………….123
SUB-CODE D1 ………………………………………………………………………………..126
SUB-CODE D2 ………………………………………………………………………………..136
SUB-CODE D3 ………………………………………………………………………………..146
SUB-CODE D4 ………………………………………………………………………………..156
Agreed Procedure No. 1 ……………………………………………………………………166
Agreed Procedure No. 2…………………………………………………………………..175
Agreed Procedure No. 3…………………………………………………………………..184
Agreed Procedure No. 4…………………………………………………………………..195
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1 Introduction
1.1 This Distribution Metering Code sets out the requirements for Metering and for
Generator Metering Circuits for Apparatus with a rating of 70 kVA and above
connected to the Distribution System. It covers in relation to such Apparatus:
(a) Metering for Active and Reactive Energy; and
(b) Generator Metering Circuits.
The Distribution Metering Code deals with Metering at Relevant Connection Sites,
as further provided in this Distribution Metering Code.
1.2 The Distribution Metering Code does not apply in respect of Imports below 70kVA
at Power Stations and in such circumstances the relevant Connection Agreement will
specify the Metering requirements.
1.3 Prior to the introduction of the Single Electricity Market (SEM) on the Island of
Ireland on 1 November 2007, the requirements for Metering for Users, whether they
were connected to the Transmission System or to the Distribution System, were
contained in the Grid Code Metering Code.
1.4 With the full licence separation of the TSO from the DNO at the introduction of the
SEM in November 2007, the DNO became responsible for a separate Distribution
Code.
1.5 The Grid Code Metering Code continues to specify the metering requirements for:
(a) Apparatus connected to the Transmission System; and
(b) Power Stations which are subject to Central Dispatch and are connected to the
Distribution System.
1.6 Users shall, in respect of Plant and Apparatus described in paragraph 1.5(b) above,
also be required to comply with the requirements of the Grid Code Metering Code.
Unless otherwise specifically provided in this Distribution Code, the provisions of
both the Grid Code and the Distribution Code have been designed so that compliance
with the metering requirements in the Grid Code Metering Code should ensure that
there will be compliance with the relevant parts of this Distribution Metering Code.
1.7 In addition to the requirements for Metering and Generator Metering Circuits set out
in this Distribution Metering Code there may be provisions in each of the Trading
and Settlement Code, Market Registration Code (“MRC”), Schedule 7 of the
Order, Connection Agreement, Grid Code and other industry documentation that
apply to certain Users connected to the Distribution System in respect of their
Apparatus.
1.8 The Distribution Metering Code specifies the requirements in respect of:
(a) technical, design and operational criteria;
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(b) accuracy and calibration;
(c) approval, certification and testing; and
(d) meter reading and data management.
1.9 The Distribution Metering Code is divided into:
– the Main Code;
– the Sub-Codes; and
– the Agreed Procedures.
1.10 In general, the Main Code contains the broader principles applying to Metering and
the Sub-Codes, Agreed Procedures and, in certain cases, the relevant Retail Market
Procedures under the MRC contain the more detailed technical requirements and/or
procedures. The Sub-Codes, Agreed Procedures and relevant Retail Market
Procedures cover, amongst other things, the following matters:
(a) Metering Sub-Codes:
Sub Code No Subject
1 For the Metering of circuits > 100 MVA
2 For the Metering of circuits > 10 MVA and ≤ 100 MVA
3 For the Metering of Circuits > 1 MVA and ≤ 10 MVA
4 For the Metering of Circuits ≥ 70 kVA and ≤ 1 MVA
(b) Agreed Procedures
AP No Subject
AP1
Maintenance, testing, inspection and sealing of Metering
(Generation) and Generator Metering Circuits.
AP2 Maintenance, testing, inspection and sealing of Metering.
AP3 Meter advance reconciliation (Generation).
AP4
Validation, estimation and substitution rules for half-hourly
data
2 Objectives
2.1 The objective of the Distribution Metering Code is to ensure that Metering
requirements are specified for Users’ Apparatus with a rating of 70 kVA and above
connected to the Distribution System.
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3 Scope
3.1 This Distribution Metering Code applies to the DNO and to Users, which in the
Distribution Metering Code means:
(a) Generators in respect of Apparatus with a rating of 70kVA and above
connected to the Distribution System; and
(b) Suppliers in respect of the supply they make to their Demand Customers
whose Apparatus is of a rating of 70 kVA and above connected to the
Distribution System.
4 Procedure
4.1 Active and Reactive Energy and Active and Reactive Power Exported or Imported
by Users shall be metered as required by this Distribution Metering Code.
4.2 Metering must be designed and installed so as to measure both Exports to and Imports
from the Distribution System and, in the case of Generating Unit(s) registered under
the Trading and Settlement Code, output from each Generating Unit. Where a
number of Generating Units have been registered as one unit under the Trading and
Settlement Code the combined output, rather than the individual outputs, from those
Generating Units may with the agreement of the DNO be measured with a single set of
Metering.
4.3 Data from Metering required under this Distribution Metering Code shall be
collected:
(a) in the case of Users not subject to Central Dispatch, by the DNO; and
(b) in the case of Users subject to Central Dispatch, by the TSO,
in each case through the relevant DNO Data Collection System.
4.4 Description of Metering:
(a) Metering subject to this Distribution Metering Code shall comply with the
requirements set out in the relevant Metering Sub-Code.
(b) All Metering for Apparatus connected to the Distribution System which is
required to comply with the Grid Code Metering Code shall be compatible
with the TSO Data Collection System.
(c) All Generator Metering Circuits must be compatible with the relevant
Metering.
5 Ownership and Meter Responsible Person
5.1 All Metering shall be owned by the DNO.
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5.2 The DNO shall ensure that all such Metering complies with this Distribution
Metering Code, other than:
(a) all Metering relating to Demand Customers which shall, for the purposes of
this Distribution Metering Code, be the responsibility of the relevant Supplier.
(b) all Generator Metering Circuits which shall, for the purposes of this
Distribution Metering Code, be the responsibility of the Generator which
operates the Generating Unit to which they relate; and
(c) all Metering relating to Interconnectors, responsibility for which shall be
governed by the provisions of the relevant Interconnection Agreement.
The DNO or the User responsible for Metering shall be known in this Distribution
Metering Code as the Meter Responsible Person in respect of such Metering.
5.3 Metering
(a) Each of the DNO and each User acting in its capacity as a Meter Responsible
Person or as a Generator shall, by the date such person becomes bound by this
Distribution Metering Code (and in respect of that Metering or those
Generator Metering Circuits for which it is responsible), ensure such
Metering or Generator Metering Circuits are properly installed and that they
comply with the requirements of this Distribution Metering Code.
(b) Details of such Metering or Generator Metering Circuits shall be provided by
the relevant Meter Responsible Person or Generator to the DNO on request
for the purposes of maintaining the register pursuant to paragraph 9.5.
Maintenance and replacement of Generator Metering Circuits in the ordinary
course shall be the responsibility of the relevant Generator.
5.4 Position
5.4.1 All current and voltage transformers associated with Metering must be installed
as close as reasonably practicable to the Connection Point taking into account
physical location and cost.
5.4.2 CTs and VTs which are part of Generator Metering Circuits must be installed
in positions which will enable the measurement of Settlement Values.
5.4.3 Generator Metering Circuits and Metering shall comply with the applicable
sections of Sub-Codes Nos. 1 to 4.
6 Data Collection
6.1 DNO
The DNO shall have the right to collect data relating to Active Energy and Reactive
Energy Imported and Exported by remote interrogation (either direct or through the
TSO) or manual on-site interrogation in accordance with the terms of this Distribution
Metering Code.
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6.2 Generators
For the purposes of remote interrogation the DNO may use its own data
communications network or failing this, shall enter into, manage and monitor contracts
to provide for the maintenance of all data links by which data is passed from System
Data Collectors to the DNO. In the event of any fault or failure on such
communication lines or any error or omission in such data the DNO shall, if possible,
retrieve such data by manual on-site interrogation in accordance with Agreed
Procedure No.4 or, as the case may be, Retail Market Procedure MP NI 105 failing
which it shall estimate the same in accordance with Agreed Procedure No.4 or Retail
Market Procedure MP NI 105a as appropriate.
6.3 Each of the DNO and all Users shall use communications protocols in relation to
Metering in accordance with the relevant Sub-Code.
7 Accuracy
Metering shall be accurate within the prescribed limits set out in the relevant Sub-
Codes. These prescribed limits shall be applied after adjustments have been made in
accordance with the relevant Sub-Code to compensate for any errors due to measuring
current and voltage transformers and connections thereto and/or due to Generator
Metering Circuits.
8 Calibration
Each Meter Responsible Person shall ensure that all Metering for which it is
responsible and each Generator shall ensure that all Generator Metering Circuits for
which it is responsible shall be calibrated or compensated in accordance with this
Distribution Metering Code in order to meet the accuracy requirements in the Sub-
Codes. The Meter Responsible Person in the case of Metering or the DNO in the
case of Generator Metering Circuits shall be granted access to such Metering or
Generator Metering Circuits by the relevant User upon reasonable notice and at
reasonable times, in order to make or inspect any adjustments to them and to attend any
tests or inspection of them required pursuant to this Distribution Metering Code.
9 Proper Order, Testing, Sealing and Reading
9.1 Proper Order:
(a) Each Meter Responsible Person shall at its own cost and expense keep in good
working order, repair and condition all Metering in respect of which it is the
Meter Responsible Person to the extent necessary to ensure the correct
recording and transmission of the requisite data relating to or in respect of the
quantity of Active and Reactive Energy measured by the relevant Metering.
(b) Each Generator shall at its own cost and expense keep in good working order,
repair and condition all Generator Metering Circuits for which it is
responsible.
9.2 Testing:
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(a) Any new or replacement meters shall be calibrated prior to installation in
accordance with the provisions of the relevant Sub-Code.
(b) Any new, replacement or modified Metering shall be tested by the Meter
Responsible Person as soon as is reasonably practicable after installation or
modification of such Metering. Metering for consumers will be tested in
accordance with the Meters (Certification) Regulations (NI) 1998.
(c) No less frequently than every five years (or more frequently if required by the
relevant Sub-Code) each Meter Responsible Person shall carry out a periodic
calibration of all Metering in respect of which it is the Meter Responsible
Person.
(d) The Meter Responsible Person in respect of Metering at a Power Station shall
give the DNO or (in the case of Metering of which the DNO is the Metering
Responsible Person), the Generator at least one month’s prior written notice of
a routine test and 5 Business Days’ prior written notice in the case of every site
test of new, replacement or modified Metering. The notice must state the date,
time, work required and estimated duration of every such test except where such
test is carried out as a result of an emergency or equipment failure in respect of
Metering which is already in service.
(e) The DNO or the Generator, as the case may be, shall have the right to attend
any such test should it so require. Any such test shall comply with the relevant
Sub-Code.
(f) If the DNO or any User has reason to believe that Metering or Generator
Metering Circuits are not performing properly or within the prescribed limits
of accuracy referred to in the relevant Sub-Code then such person (where it is
not the DNO) shall promptly notify the DNO accordingly. An ad-hoc test may
then be arranged which will only be chargeable to the requesting party if no
fault is found.
(g) The costs and expenses of testing carried out under paragraph 9.2(b) and
calibration carried out under paragraph 9.2(c) shall be borne by the Meter
Responsible Person. The costs and expenses of testing carried out under
paragraph 9.2(f) shall to the extent that testing reveals no fault, be borne by the
party requesting such test and, to the extent that such test reveals faults, by the
Meter Responsible Person.
(h) If all or any part of a Generator Metering Circuit is replaced, the relevant
Generator Metering Circuit shall be recalibrated if calibration is possible. If
required, the DNO and the Generator shall agree any change that may be
necessary to the existing compensation for that Generator Metering Circuit.
(i) Calibration certificates for test equipment shall be made available by the DNO
for inspection by the relevant Generator and the relevant User.
9.3 Testing: General
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(a) Any testing of any Metering or Generator Metering Circuits will be carried
out by the Meter Responsible Person in the case of Metering, or by the
Generator in the case of Generator Metering Circuits, on the relevant
Metering or Generator Metering Circuits mounted in their operational
position.
(b) Both the Generator and the Meter Responsible Person and (where the DNO is
not the Meter Responsible Person) the DNO shall have the right to attend all
such tests. All testing will be carried out in accordance with the relevant Sub-
Code. Any breaking of seals and sealing on Metering will be carried out in
accordance with Agreed Procedure No.1 or, as the case may be, Agreed
Procedure No. 2. The test performance of any Metering or Generator
Metering Circuits shall be compared with calibrated test equipment by one of
the following methods:
(i) injecting into the measuring circuits (i.e. excluding the primary current
and voltage transformers) and comparing the readings or records over
such period as may reasonably be required by the DNO or, where a
Generator has instigated the test, by that Generator to ensure a reliable
comparison; or
(ii) where practicable, operating the calibrated test equipment from the same
primary current and voltage transformers as the meter under operating
conditions. The readings or recordings of the meter and the calibrated
test equipment shall be compared over such period as may reasonably be
required by the DNO or, where an Generator has instigated the test, by
that Generator to ensure a reliable comparison; or
(iii) in any other circumstances, such other method as may be reasonably
specified by the DNO or, where a Generator has instigated the test, by
that Generator.
9.4 Test Failures
(a) Any meter which fails any test whilst in its operational position shall be
removed by the Meter Responsible Person forthwith and tested by the DNO
under laboratory conditions in accordance with the relevant Sub-Code in the
presence of the Meter Responsible Person or the Generator if either wishes to
attend. The DNO shall give the Meter Responsible Person or the Generator,
as the case may be, prior notice of such test.
(b) For meters removed in accordance with paragraph 9.4(a) on circuits that are
required to remain in service either:
(i) the meter shall be replaced by the Meter Responsible Person forthwith
with a previously recalibrated meter suitably prepared and compensated
for the circuit; or
(ii) where the Metering includes both main and check meters for the
affected circuit, and the meter (main or check) which is to remain on site
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is within its calibration period, such other meter may be removed
provided it is returned to site or replaced within 10 Business Days.
(iii) In such circumstances where the remaining meter is the check meter it
shall, for all estimation or retrieval purposes, be regarded as the main
meter until replacement or return to site of the main meter.
9.5 Records:
(a) Each Meter Responsible Person shall at its own cost and expense maintain a
register in relation to Metering for which it is the Meter Responsible Person.
(b) Each Generator shall at its own cost and expense maintain a register in relation
to Generator Metering Circuits for which it is responsible.
(c) Each such register shall detail any relevant Compensation Factors,
specification details, e.g. serial number and accuracy class, and all relevant
matters as may be required by the relevant Sub-Code relating to testing and
calibration including the dates, location and results of any tests, readings,
adjustments or inspections carried out, any temporary or permanent replacement
of meters and the dates on which any seal was applied or broken, the reason for
any seal being broken and the persons carrying out and attending any such tests,
readings, inspections or sealings. Such records shall also include any other
details as may be reasonably required by the DNO.
(d) Any such records shall be complete and accurate and retained for a minimum
period of 7 years whilst the Metering or Generator Metering Circuit continues
to be in service at the Relevant Connection Site and for 12 months or such
longer period as may be required under any other relevant industry document
following the permanent removal of the relevant Metering or Generator
Metering Circuits.
(e) Any data which forms part of such records shall be made available to the
Generator in the case of Metering and the DNO in the case of Generator
Metering Circuits. Copies of the results of all manual readings, adjustments,
tests and inspections shall be provided to the Meter Responsible Person or
Generator in accordance, where appropriate, but without limitation, with the
Agreed Procedures.
(f) Each Meter Responsible Person shall on request pass such records or copies of
the same to its successor as Meter Responsible Person in relation to any
Metering.
9.6 Sealing:
(a) All Metering as is capable of being made secure shall be sealed by or on behalf
of each Meter Responsible Person and either the DNO or the Generator as is
appropriate and following any test or inspection thereof in accordance with
Agreed Procedure No.1 or, as the case may be, Agreed Procedure No. 2
except, where sealing is impractical in the reasonable opinion of such Meter
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Responsible Person and either the DNO or the Generator as is appropriate
having regard to the physical and electrical configuration at each Relevant
Connection Site.
(b) Each Generator and the DNO shall make arrangements for all Generator
Metering Circuits as are capable of being made secure to be sealed by or on its
behalf in accordance with Agreed Procedure No. 1, except where impractical
in the reasonable opinion of the relevant Generator and the DNO having regard
to the physical and electrical configuration at each Relevant Connection Site.
(c) The extent and nature of the sealing arrangements shall be agreed by the DNO
and the Generator at the design stage of the main connection.
(d) No seal applied pursuant to this Distribution Metering Code shall be broken or
removed except in the presence of or with the prior consent of the DNO or the
User affixing the seal or on whose behalf the seal has been affixed unless it is
necessary to do so in circumstances where both main and check meters are
malfunctioning or there occurs a fire or other similar hazard and such removal
is essential and such consent cannot be obtained (provided that the person which
has affixed the seal and which has not given such consent shall be informed
forthwith thereafter). Where verbal consent is given it must be confirmed in
writing forthwith.
(e) Neither the DNO nor the relevant User shall incur any liability under this
Distribution Metering Code in the event it cannot perform any of its duties
hereunder due to any such consent required by paragraph 9.6(d) being withheld
save that it shall promptly inform the DNO and the relevant Meter Responsible
Person or Generator accordingly.
(f) Each User shall control the issue of its own seals and sealing pliers, and shall
keep an accurate register of all such pliers and the authorised persons to whom
they are issued.
(g) Each seal must be uniquely identified in a format previously agreed with the
DNO. A seal application and removal record must be maintained and signed off
by both parties.
9.7 Inspection and Readings:
(a) The DNO shall ensure that all meters forming part of Metering which is subject
to the terms of this Distribution Metering Code are inspected and read by onsite
interrogation by it or on its behalf not less than once every 5 years and shall
give the Meter Responsible Person or the Generator at least 5 Business Days’
prior notice thereof or such shorter period as the DNO and the relevant User
may agree.
(b) A failure to notify in accordance with paragraph 9.7(a) shall invalidate the
results of any such inspection or reading. Each reading shall be taken at, or as
close as is practicable to, the end of a Settlement Period (as that term is defined
in the Trading and Settlement Code).
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(c) The DNO shall keep written reports of all such inspections and readings and
provide copies to the Meter Responsible Person or the Generator for the
purposes of paragraph 9.5(a). Any resulting discrepancies will be dealt with as
provided in the relevant Agreed Procedure.
(d) The Meter Responsible Person or Generator, as the case may be shall have
the right to attend any such inspection and reading although the failure to attend
shall not prevent such inspection or reading taking place nor invalidate its
results. The representative of the Generator or Meter Responsible Person
shall acknowledge the results of any such inspection or reading in the manner
required by the Agreed Procedure.
10 Access
10.1 Each User hereby agrees to grant to each other User and to the DNO, and the DNO
hereby agrees to grant to each User, its employees, agents and contractors and persons
duly authorised by them (each an “Invitee”) full right to enter upon and through and
remain upon any part of such person’s property to the extent necessary for the purposes
of this Distribution Metering Code subject to the other provisions of paragraph 10.
Each person so granting access must further ensure that any consents or other forms of
approval of third parties required in respect of such access have been correctly obtained
and remain valid at the time of such access including, if appropriate, rights of access
across third party land.
10.2 Each of the DNO and each User shall ensure, so far as it is able, that physical access to
Metering and Generator Metering Circuits is, where practicable, restricted to
personnel who are required to have such access for the proper performance of their
duties and have received permission for such access. A record of any such access shall
be maintained by the DNO or the User, as the case may be, on whose land the
Metering or Generator Metering Circuits are positioned, with copies provided to the
Meter Responsible Person and the DNO pursuant to paragraph 9.5(f). In addition all
Metering and Generator Metering Circuits, where practicable, must be made secure,
if necessary by making the lock and keys subject to similar access restrictions.
10.3 Subject to any other arrangements which may be agreed between the relevant User and
the DNO or another User, as the case may be, the right of access provided for in
paragraph 10.1 includes the right to bring on to such property such vehicles, plant,
machinery and maintenance or other materials as shall be necessary for the purposes of
this Distribution Metering Code.
10.4 Each of the DNO and each User shall ensure that any particular authorisation or
clearance for any Invitee which is required to be given to ensure access by such Invitee
is available on the arrival of such Invitee at the Relevant Connection Site.
10.5 Each of the DNO and each User shall ensure that all reasonable arrangements and
provisions are made and/or revised from time to time as and when necessary or
desirable to facilitate the safe exercise of any right of access granted pursuant to
paragraph 10.1 with the minimum of disruption, disturbance and inconvenience. Such
arrangements and provisions may, to the extent that the same is reasonable, limit or
restrict the exercise of such right of access and/or provide for any of the DNO and each
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User to make directions or regulations from time to time in relation to a specified
matter.
10.6 Matters to be covered by such arrangements and/or provisions include:
(a) the identification of the relevant Metering or Generator Metering Circuits;
(b) the particular access routes applicable to the land in question having particular
regard for the weight and size limits on these routes;
(c) any limitations on times of exercise of the right of access;
(d) any requirements as to prior notification and as to authorisation or security
clearance of individuals exercising such right of access and procedures for
obtaining the same;
(e) the means of communication to the Invitee of any relevant directions or
regulations made by the person granting access; and
(f) the identification of and arrangements applicable to personnel exercising the
right of access granted by paragraph 10.1; and
(g) safety procedures.
Each Invitee shall observe and comply with any such arrangements and all provisions
(or directions or regulations issued pursuant thereto) made from time to time.
10.7 Each Invitee shall ensure that all reasonable steps are taken in the exercise of any right
of access by such Invitee to:
(a) avoid or minimise damage in relation to the property over which it has access;
and
(b) cause as little disturbance and inconvenience as possible to any of the DNO or
any User as the case may be, or other occupier of such property,
and shall make good any damage caused to any such property in the course of exercise
of such rights as soon as may be practicable. Subject to this, all such rights of access
shall be exercisable free of any charge or payment of any kind.
10.8 For the avoidance of doubt, no User or the DNO shall incur any liability under this
Distribution Metering Code in the event it cannot perform any of its duties hereunder
due to access to Metering or Generator Metering Circuits being denied to it save that
such person (where not the DNO) shall promptly inform the DNO, the relevant Meter
Responsible Person and the Generator accordingly.
11 Disputes
11.1 Any dispute in relation to the following matters:
(a) siting of Metering;
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(b) technical specifications for Metering, Generator Metering Circuits or the
DNO Data Collection System;
(c) sealing of Metering;
(d) compliance of Metering or Generator Metering Circuits with technical
specifications of the Distribution Metering Code;
(e) compensation values;
(f) such other matters as the relevant persons in dispute under this Distribution
Metering Code may agree,
shall be referred to an Independent Engineer under paragraph 11.2.
11.2 The parties to a dispute under this paragraph 11 agree and shall procure that the
Independent Engineer shall act as an expert and not as an arbitrator and shall decide
those matters referred or reserved to him under this paragraph 11 by reference to Good
Industry Practice using his skill, experience and knowledge and with regard to such
other matters as the Independent Engineer in his sole discretion considers appropriate.
All references to the Independent Engineer shall be made in writing by either party
with notice to the other being given contemporaneously as soon as reasonably
practicable and in any event, within 14 days of the occurrence of the dispute to be
referred to the Independent Engineer. The parties shall promptly supply the
Independent Engineer with such documents and information as he may request when
considering such question. The Independent Engineer shall use his best endeavours to
give his decision upon the question before him as soon as possible following its referral
to him and in any event within 21 days of such referral. The fees and expenses of the
Independent Engineer shall be shared equally the parties to the dispute. The parties to
the dispute expressly acknowledge that submission of disputes under this paragraph 11
for resolution by the Independent Engineer does not preclude subsequent submission
of disputes for resolution by arbitration as provided for in the Distribution Code.
Pending any such submission the parties shall treat the Independent Engineer’s
decision as final and binding. The Independent Engineer will be a Member of the
Association for Consultancy and Engineering (ACE) and shall be agreed between the
parties within 7 days of a dispute being referred or such other period as may be agreed
between the parties to the dispute. Failing agreement it shall be referred to the
President of the Institution of Electrical Engineers who shall nominate the Independent
Engineer.
11.3 Any other dispute under this Distribution Metering Code shall be dealt with in
accordance with the disputes procedure in the relevant Connection Agreement.
11.4 Any testing of Metering or Generator Metering Circuits required to settle a dispute
will be carried out in accordance with paragraphs 9.3 and 9.4.
11.5 Notwithstanding paragraphs 11.1 to 11.4, any dispute under this Distribution
Metering Code in relation to a matter that is also subject to the dispute resolution
procedures contained within the Trading and Settlement Code and the MRC will be
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dealt with in accordance with the relevant dispute resolution procedure contained within
the MRC.
11.6 If at any time any Metering equipment is destroyed or damaged or otherwise ceases to
function, or is found to be outside the prescribed limits of accuracy referred to in the
Sub-Codes, the DNO will promptly adjust, renew or repair the same. If at any time
any Metering circuit not under the ownership of the DNO is destroyed or damaged or
otherwise ceases to function, or is found to be outside the prescribed limits of accuracy
referred to in the Sub-Codes, the Generator will promptly adjust, renew or repair the
same. In the event that a Generator cannot or does not comply with its obligations to
repair, adjust or replace or renew any defective component, the DNO shall have the
right to carry this out and to recover its own costs and expenses from the Generator.
12 Information
12.1 Where a relevant User has an agreement with the DNO to receive electronic data from
Metering, such User shall install such computer equipment as may be necessary for
such purpose and which shall be compatible with such Metering and shall comply with
any relevant requirement of the Agreed Procedures. Each such User shall be
responsible for its own computer equipment and communication lines.
12.2 Each Generator shall have the right to receive electronic data from Metering in
respect of which it is the Generator. The DNO shall not, without good cause, interrupt
or otherwise disturb such electronic data. The Generator shall be responsible for the
maintenance of any communication lines from the Generator Data Collector to the
relevant Generator.
12.3 Demand Customers shall not have the right to receive electronic data files for
Metering from the DNO in respect of which it is the Demand Customer.
12.4 All Users shall give to the DNO all such information in their possession regarding
Metering as the DNO shall reasonably require for the proper functioning of the Data
Collection System including information regarding the dates and time periods for
installation of new Metering, wiring diagrams, and the dates and periods when
Metering is out of service.
13 Ownership of Metering Data
13.1 The Meter Responsible Person of any Metering shall own the data acquired
therefrom. Any of the DNO and each User to whom such data relates shall at all times
have the right to and is hereby authorised to have access to such data and to use such
data in each case as may be permitted pursuant to this Distribution Metering Code.
13.2 The Meter Responsible Person may make a charge for the provision of such data of an
amount reflecting its reasonable costs of providing such data and, if confidential, may
only release such data to others to the extent required pursuant to this Distribution
Code or as permitted by the Connection Agreement.
13.3 Any person subject to this Distribution Metering Code shall, at all times, comply with
its respective obligations under all applicable Data Protection Legislation in relation to
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all Personal Data that is Processed by it in the course of performing its obligations
under this Distribution Metering Code, including maintaining any required
notification under the Data Protection Legislation. To the extent that any Personal
Data is data that is Processed for a purpose set out in the data protection provisions
contained within the MRC, any person Processing such data will be subject to those
provisions.
14 New Connection Registration and Change of Supplier
14.1 The procedures for registration of a new connection in Northern Ireland and for a
change of Supplier are set out in Retail Market Procedures MP NI 101 and MP NI
102 respectively. Additional guidance relating to these procedures is set out in the
market guide(s) associated with Retail Market Procedures MP NI 101 and MP NI
102.
15 Notices
15.1 Any notice of a new Meter Responsible Person or of a change in Meter Responsible
Person or any other communication required under this Distribution Metering Code
to be given to the DNO shall if required be sent by facsimile to number: 02890 954
329, at NIE Market Services, Fortwilliam House, attention: Metering Systems Manager
(with hard copy to follow by first class post) or such other facsimile number and
address as may from time to time be nominated in writing by the DNO and, if required
to be given to any other User, shall be sent by facsimile to such number at such address
and to such person as such User shall nominate in writing to the DNO (with hard copy
to follow by first class post). In the absence of nomination such communication as is
required shall be sent to the registered office of such other User.
15.2 Any notice or other communication sent by facsimile pursuant to paragraph 15.1 shall
be deemed to have been received when despatched.
15.3 A new Meter Responsible Person must be notified to the DNO at least 20 Business
Days prior to either:
(a) the date of the intended commencement of obligations of the Meter Responsible
Person; or
(b) the date of simultaneous termination of obligations by the existing Meter
Responsible Person and the assumption of those obligations by the new Meter
Responsible Person,
(as the case may be) in connection with the relevant Metering.
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SUB-CODES
Summary of Technical Requirements for Distribution Connected Metering Systems
The Metering System technical requirements for Distribution connections are similar to those
at Transmission level. The fundamental Metering attribute which must be specified for
different circuit loads or generator outputs is that of meter accuracy.
A summary of these accuracy requirements is given in the table below and the Sub-Codes that
follow provide more detailed information;
a) Technical Standards Matrix
>100MVA
CTs 0.2S
VTs 0.2
Meters 0.2S
Main/Check Meters Y
Main/Check CTs & VTs Y
3 Phase 4 Wire Required Y
10-100MVA
CTs 0.2
VTs 0.5
Meters 0.5S
Main/Check Meters Y
Main/Check CTs & VTs Y
*3 Phase 4 Wire Required N
1-10MVA
CTs 0.5S
VTs 1.0
Meters 0.5
Main/Check Meters Y
Main/Check CTs & VTs N
*3 Phase 4 Wire Required N
<1MVA
CTs 0.5S
VTs 1
Meters 2
Main/Check Meters N
Main/Check CTs & VTs N
*3 Phase 4 Wire Required N
b) Technical Design Considerations
Specific design details may on occasions require consideration by the DNO and the User on a
case by case basis depending on the nature of the installed electrical connection and its
associated plant.
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If any of the above accuracy levels cannot be individually achieved e.g. due to size constraints
within switchgear, it may be possible with the permission of the DNO to increase the accuracy
of other elements such that the overall Metering System accuracy remains within the
prescribed limits.
The burden of Metering CTs and VTs must be determined on a per site basis to ensure that it
is adequate for the purpose. CTs must operate at between 25% and 95% of their rated burden
and VTs must not exceed 95% of their rating.
* Three phase four wire Metering installations are required for generation or loads of greater
than 100MVA. However if it is anticipated that phase energy will be imbalanced, this system
of Metering should be used at other levels. MV metered connections are usually used for
lower than 1 MW capacity, are considered unbalanced and therefore must be measured using
three phase four wire methods of Metering.
The star point of Metering VTs must be earthed irrespective of the Metering System
deployed.
All Metering CTs must be individually wired out to Metering equipment panels i.e. the use of
common return conductors is prohibited.
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SUB-CODE D1
Demand Customer Connected Load or Generation > 100MVA
Contents
1 Scope
2 Standards
3 Facilities to be provided at Metering points
3.1 General
3.2 Meters
3.3 Instrument Transformers
3.4 Data Collectors
3.5 Data Collection System
3.6 Facilities
4 Measurement criteria
4.1 Accuracy
4.2 Compensation for Errors
5 Calibration and testing of Metering
5.1 Meters
5.2 Current and Voltage Transformers
5.3 Test Access to Metering Equipment
5.4 Data Collectors
5.5 Records
Appendix
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1 Scope
1.1 This Sub-Code D1 specifies the Metering facilities which must be provided and certain
practices that must be employed for the measurement of electrical energy flows
associated with:
(a) Suppliers in relation to their Demand Customers; and
(b) Generating Units.
1.2 This Sub-Code supplements the Main Code of the Distribution Metering Code to
which reference should be made. In the event of an inconsistency between the
provisions of this Sub-Code and the Main Code, the provisions of the Main Code
shall prevail.
1.3 This Sub-Code should also be read in conjunction with any relevant Agreed
Procedures and Schedule 7 of the Order.
1.4 This Sub-Code applies to circuits with a rated capacity which exceeds 100 MVA.
2 Standards
All references to industry standards given in the text of this Sub-Code are to versions
which are current as at 1 November 2007. However, Metering is required to comply
with the version of any such standard, equivalent or replacement which is in force at
the date of installation.
3 Facilities to be Provided at Metering Points
3.1 General
Although for clarity the specification identifies separate items of equipment, nothing in
this Sub-Code prevents the items being combined to perform the same task provided
the requirements of this Sub-Code are met.
3.2 Meters
3.2.1 For each circuit the following energy measurements are required at or in
relation to the Connection Point:
(a) Active Energy for Import (kWh);
(b) Active Energy for Export (kWh) (applicable to Generators only);
(c) Reactive Energy for Import and Export (kVArh).
3.2.2 The Meter Responsible Person shall ensure that Metering for the above
measurements shall normally be provided on the User’s side of the Connection
Point in order to measure required Settlement Values.
3.2.3 Active Energy Meters (kWh)
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Active Energy meters shall comply with the relevant part of BS EN 62053 (or
the standard current at the date of design of such equipment) for class 0.2S
meters.
3.2.4 Reactive Energy Meters (kVArh)
Reactive Energy meters shall comply with the relevant requirements of IEC
Standard 1268 for class 2 meters.
3.2.5 The measurements will be produced using the outputs from current transformers
and voltage transformers.
3.2.6 Each circuit will be provided with:
(a) main kWh meter;
(b) check kWh meter;
(c) two main kVArh meters or one bi-directional kVArh meter for lagging
and leading power factors; and
(d) two check kVArh meters or one bi-directional kVArh meter for lagging
and leading power factors.
Paragraph 3.2.9 deals with the situation where Import and/or Export of Active
Energy is required at the same point where a single meter can be used.
3.2.7 If direct measurement of the required values cannot be achieved, then the
required values may be calculated using values measured at other points subject
to prior agreement with the DNO and providing the Overall Accuracy meets
the requirements of paragraph 4.1. Where compensation is applied the values
shall be recorded and supporting evidence shall be available to justify the
compensation criteria.
3.2.8 Where the Import and/or Export of Active Energy and Reactive Energy is
required to be measured at the same point, these functions may be combined in
a single meter in which each energy flow is measured separately.
3.2.9 Meters shall be labelled in accordance with the Appendix of this Sub-Code.
3.3 Instrument Transformers
3.3.1 The terms “current transformer” (CT) and “voltage transformer” (VT) used in
this Sub-Code do not preclude the use of other measuring techniques providing
the accuracy, and also the longer term accuracy in accordance with this Sub-
Code can be verified to the DNO’s satisfaction.
3.3.2 In accordance with the principles in paragraph 3.2.2, all CTs and VTs will be
fitted on the User’s side of the Connection Point except where otherwise
agreed with the DNO.
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3.3.3 Where CTs and/or VTs are used, they shall meet the requirements set out in
paragraphs 3.3.5 and 3.3.6 below.
3.3.4 Where CTs and/or VTs are used then a test terminal block or equivalent facility
shall be provided close to the meter(s). This facility will be fitted with the DNO
seals.
3.3.5 Current Transformers
(a) Two sets of CTs to IEC 60044-1 (or the standard current at the date of
design of such equipment) with a minimum standard of accuracy class
0.2S shall be provided per circuit and shall also meet (to the extent
applicable) any meter certification regulations in force at the time.
(b) Each CT secondary winding supplying a main meter shall be dedicated
to Metering purposes only. Each CT secondary winding only supplying
a check meter may be used for other purposes so long as such other uses
do not degrade the accuracy of the check meter outside the limits
required by paragraph 4.1.1 and sub-paragraph (f) below, and the DNO
is notified of such other uses in accordance with sub-paragraph (g)
below.
(c) Where a CT circuit has an additional burden not associated with meters,
this additional burden shall not be modified in any way without obtaining
the approval of the DNO in accordance with sub-paragraph (g) below.
(d) Common return leads for two or more CT secondary circuits are not
permitted.
(e) Main and check meters must be connected to different CTs.
(f) The total burden on CTs shall not exceed their rating at the rated
secondary current.
(g) Where any of the foregoing provisions of this paragraph 3.3.5 permit a
modification to CT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.5
and also to ensure there is no degradation of the accuracy required by
paragraph 4.1.1.
3.3.6 Voltage Transformers
(a) Two VTs, or one VT with two or more secondary winding sets, to IEC
60044-2 (or the standard current at the date of design of such equipment)
with a minimum standard of accuracy class 0.2 shall be provided for the
Metering of each circuit and shall also (to the extent applicable) meet
any meter certification regulations in force at the time.
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(b) Capacitor VTs shall have a working burden which provides for
monitoring of the integrity of each fuse and which does not exceed the
maximum rating or fall below the minimum rating stipulated by the
relevant manufacturer.
(c) Each VT secondary winding supplying a main meter shall be dedicated
to Metering purposes only. Each VT secondary winding only supplying
a check meter may be used for other purposes so long as other uses do
not degrade the accuracy of the check meter outside the limits required
by paragraph 4.1.1 and sub-paragraph (g) below and the DNO is notified
of such other uses in accordance with subparagraph (h) below.
(d) Where a VT circuit has an additional burden not associated with meters,
this additional burden shall not be modified in any way unless the
approval of the DNO is obtained in accordance with subparagraph (h)
below.
(e) Each meter circuit shall be fed by a separate, fused supply from the VT.
(f) Main and check meters must be connected to different VTs. If the VT
supplies other equipment, separate fusing must be provided for the
Metering.
(g) The total burden on VTs shall not exceed their rating at the rated
secondary voltages.
(h) Where any of the foregoing provisions of this paragraph 3.3.6 permit a
modification to VT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.6
and also to ensure there is no degradation of accuracy as required by
paragraph 4.1.1.
3.3.7 Existing Installations
For installations connected to the Distribution System prior to 1 January 2010
the installed instrument transformers may be used irrespective of their accuracy
class providing the Overall Accuracy requirements as defined in paragraph 4.1
are met and also the following:
(i) in the event of a significant alteration to the primary plant (e.g. a
switchgear change), new instrument transformers which comply with
paragraphs 3.3.5 and 3.3.6 shall be provided;
(ii) separately fused VT supplies shall be provided for each of the
following:-
(a) the main meters;
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(b) the check meters; and
(c) any additional electrical burden.
3.4 Data Collectors
3.4.1 Data collectors may be either an integral part of individual circuit meters or
stand alone units which collect pulses from one or more individual meters.
Duplicate data collectors may also be an integral part of check meters or stand
alone units. These will be provided by the Meter Responsible Person and used
to collect, store and transmit energy values for each Settlement Period to a
DNO Data Collection System.
3.4.2 The following is required:
(a) the data collectors must have sufficient data channels to store all halfhour
value types necessary for settlement (e.g. kWh and kVArhA
Import and Export per connection) and be capable of storing these
values during failure of the AC power supply;
(b) on demand from the DNO Data Collection System the data collector
will transfer the recorded Settlement Values without loss or error. The
Settlement Values must also be transferable manually using a portable
collection device (personal computer/hand held unit/removable memory
module etc) of a type compatible with the system used by the DNO; and
(c) in the event of failure of communications with the central collection
station the data collector will be capable of storing a minimum of five
channels of data per connection for a minimum period of 20 days with an
integrating period of 30 minutes. This 20 day period may reduce pro rata
dependent on the notified demand period selected as described in
paragraph 3.4.3 below. Access to the manual transfer facility will be
secured from unauthorised interference.
3.4.3 The settlement period shall be selectable over the following range: 30, 15, and 1
minutes and will be notified by the DNO. For any selectable value in this range
one Settlement Period shall commence on the hour and half-hour.
3.4.4 Monitoring facilities shall be provided for data collector fault conditions and to
record any instances of local interrogation which changes data.
3.5 Data Collection System
3.5.1 Communications
The means of communication between the data collector and the central DNO
Data Collection System must be secure at the remote end. Communication can
be via PSTN, PTN, GPRS, GSM networks or by any other technically suitable
means which has previously been agreed with the DNO.
3.5.2 Central Collection Station
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The DNO Data Collection System will interrogate each remote meter or data
collector. All the DNO operations carried out either manually or automatically
shall be protected by password protection. The DNO Data Collection System
will synchronise the outstations during interrogation to a standard reference
time. Following receipt of all data channels from the outstation the meter data
will be transferred to the DNO’s billing and settlement systems.
3.5.3 Supply Voltage
Assured Supplies must be used where ever possible. However, where a
measurement VT source is used and the outstation is storing data for more than
one circuit, a voltage selector relay scheme using each circuit involved shall be
provided. Local and remote phase failure indications shall be provided.
3.6 Facilities
The Metering equipment shall be capable of providing voltage free (clean contacts)
relay outputs which accurately represent the recorded channel values for:
(a) kWh (Import and Export) and kVArh (lagging and leading).
(b) A 30 minute reset pulse.
4 Measurement Criteria
4.1 Accuracy
4.1.1 Overall Accuracy of Equipment
Meters shall be calibrated so as to achieve Overall Accuracy of Metering
within the limits set out below. Calibration of meters shall be adjusted due to
current and voltage transformer errors and/or errors due to lead electrical
burdens but not for primary transformer losses. Paragraph 4.2.2 deals further
with this issue.
(a) Active Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
120% to 10% inclusive
Below 10% to 5% inclusive
Below 5% to 1% inclusive*
120% to 10% inclusive
1.0
1.0
1.0
0.5 lag and 0.8 lead
±0.5%
±0.7%
±1.5%
±1.0%
* This requirement shall only apply where the energy transfers to be measured by the Import
meter and/or the Export meter during normal operating conditions are such that the Rated
Measuring Current will be below 5% (excluding zero) for periods equivalent to 10% or greater
per annum.
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(b) Reactive Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
120% – 10% inclusive
120% – 20% inclusive
0
0.866 lag and lead
±4.0%
±5.0%
4.1.2 Accuracy of Time Keeping
(a) The time keeping accuracy of Metering equipment shall be maintained
in accordance with Standard Time.
(b) The commencement of each Settlement Period shall be within 10
seconds of Standard Time.
(c) The duration of each Settlement Period shall be within ± 0.1% of the
required duration, except where synchronisation has occurred in a
Settlement Period.
4.2 Compensation for Errors
4.2.1 Compensation for Instrument Transformer Errors
Compensation shall be made for errors of current and voltage transformers
and/or lead electrical burdens, if possible, in the meter calibration.
4.2.2 Compensation for Power Transformer and Line Losses
Where the installed Metering location and the Connection Point do not
coincide then, where necessary, compensation for power transformer and/or line
losses shall be provided to meet the Overall Accuracy at the boundary point
defined in paragraph 3.2.2. Compensation shall be made in the relevant data
collector and the formula for calculation shall be agreed between the DNO and
the relevant User.
4.2.3 Where existing calibration records do not exist, a recalibration test shall be
carried out where practicable. Values of compensation shall be recorded and
evidence to justify the compensation criteria shall be made available for
inspection, including all test certificates.
5 Calibration and Testing of Metering
5.1 Meters
Metering Systems shall be calibrated and tested in accordance with the relevant part of
BS EN 62053 and the manufacturer’s recommendations.
5.2 Current and Voltage Transformers
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Measuring transformers shall be supplied with known characteristics within the
requirements of paragraph 3.3 of this Sub-Code.
5.3 Test Access to Metering Equipment
Metering equipment shall be provided with sealable test terminal blocks both at the
meter and if practicable at the switchgear to facilitate meter testing and current /
voltage transformer checks in situ. Test terminal block design shall be agreed in
advance with the DNO.
5.4 Data Collectors
5.4.1 Maintenance
Data collectors must be maintained in accordance with the manufacturer’s
recommendations or as otherwise necessary to meet the obligations of this Sub-
Code.
5.4.2 Testing
There is no requirement for routine tests of data collectors other than as a part
of an overall Metering System test.
5.5 Records
The results of all tests and periodic checks shall be held as a permanent record by the
DNO and a copy held by the Generator.
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APPENDIX
LABELLING OF METERS FOR IMPORT AND EXPORT
1 ACTIVE ENERGY
Active Energy is considered to be Imported when it flows to the User System from
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Import”.
Active Energy is considered to be Exported when it flows from the User System to
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Export”.
Meters shall be labelled to distinguish between main and check meters.
2 REACTIVE ENERGY
Reactive Energy is considered to be Imported or Exported as follows:
Flow of Active Energy Power Factor Flow of Reactive Energy
Import Lagging Import*
Import Leading Export*
Import Unity Zero
Export Lagging Export
Export Leading Import
Export Unity Zero
For the purposes of labelling of meters the conditions asterisked above will determine labelling
where Import for Active Energy is defined as in 1 above.
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SUB-CODE D2
Demand Customer Connected Load or Generation greater than 10MVA to 100MVA
Contents
1 Scope
2 Standards
3 Facilities to be provided at Metering points
3.1 General
3.2 Meters
3.3 Instrument Transformers
3.4 Data Collectors
3.5 Data Collection System
3.6 Facilities
4 Measurement criteria
4.1 Accuracy
4.2 Compensation for Errors
5 Calibration and testing of Metering
5.1 Meters
5.2 Current and Voltage Transformers
5.3 Test Access to Metering Equipment
5.4 Data Collectors
5.5 Records
Appendix
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1 Scope
1.1 This Sub-Code D2 specifies the Metering facilities which must be provided and certain
practices that must be employed for the measurement of electrical energy flows
associated with:
(a) Suppliers in relation to their Demand Customers; and
(b) Generating Units.
1.2 This Sub-Code supplements the Main Code of the Distribution Metering Code to
which reference should be made. In the event of an inconsistency between the
provisions of this Sub-Code and the Main Code, the provisions of the Main Code
shall prevail.
1.3 This Sub-Code should also be read in conjunction with any relevant Agreed
Procedures and Schedule 7 of the Order.
1.4 This Sub-Code applies to circuits with a rated capacity which exceeds 10 MVA and up
to and including 100 MVA.
1.5 For the purposes of this Sub-Code, the criteria for a Demand Customer supply
(Import Active Energy) to be over 10 MVA is that monthly maximum demand in each
of the three months of the highest maximum demand on the Distribution System in
each period of 12 consecutive months exceeds 10 MVA. For a new supply, a maximum
demand is formally agreed between the Demand Customer and the DNO and this is
periodically reviewed thereafter.
2 Standards
All references to industry standards given in the text of this Sub-Code are to versions
which are current as at 1 November 2007. However, Metering is required to comply
with the version of any such standard, equivalent or replacement which is in force at 1
November 2007.
3 Facilities to be Provided at Metering Points
3.1 General
Although for clarity the specification identifies separate items of equipment, nothing in
this Sub-Code prevents the items being combined to perform the same task provided
the requirements of this Sub-Code are met.
3.2 Meters
3.2.1 For each circuit the following energy measurements are required at or in
relation to the Connection Point:
(a) Active Energy for Import (kWh);
(b) Active Energy for Export (kWh) (applicable to Generators only);
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(c) Reactive Energy for Import and Export (kVArh).
3.2.2 The Meter Responsible Person shall ensure that Metering for the above
measurements shall normally be provided on the User’s side of the Connection
Point in order to measure required Settlement Values.
3.2.3 Active Energy Meters (kWh)
Active Energy meters shall comply with the relevant part of BSEN 62053 (or
the standard current at the date of design of such equipment) for class 0.5S
meters.
3.2.4 Reactive Energy Meters (kVArh)
Reactive Energy meters shall comply with the relevant requirements of IEC
Standard 1268 or BS EN 62053 (or the standard current at the date of design of
such equipment) Part 4 for class 2 meters.
3.2.5 The measurements will be produced using the outputs from current transformers
and voltage transformers.
3.2.6 Each circuit will be provided with:
(a) main kWh meter;
(b) check kWh meter;
(c) two main kVArh meters or one bi-directional kVArh meter for lagging
and leading power factors; and
(d) two check kVArh meters or one bi-directional kVArh meter for lagging
and leading power factors.
Paragraph 3.2.9 deals with the situation where Import and/or Export of Active
Energy is required at the same point where a single meter can be used.
3.2.7 If direct measurement of the required values cannot be achieved, then the
required values may be calculated using values measured at other points subject
to prior agreement with the DNO and providing the Overall Accuracy meets
the requirements of paragraph 4.1. Where compensation is applied the values
shall be recorded and supporting evidence shall be available to justify the
compensation criteria.
3.2.8 Where the Import and/or Export of Active Energy and Reactive Energy is
required to be measured at the same point, these functions may be combined in
a single meter in which each energy flow is measured separately.
3.2.9 Meters shall be labelled in accordance with the Appendix of this Sub-Code.
3.3 Instrument Transformers
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3.3.1 The terms “current transformer” (CT) and “voltage transformer” (VT) used in
this Sub-Code do not preclude the use of other measuring techniques providing
the accuracy, and also the longer term accuracy, in accordance with this Sub-
Code can be verified to the DNO’s satisfaction.
3.3.2 In accordance with the principles in paragraph 3.2.2, all CTs and VTs will be
fitted on the User’s side of the Connection Point except where otherwise
agreed with the DNO.
3.3.3 Where CTs and/or VTs are used, they shall meet the requirements set out in
paragraphs 3.3.5 and 3.3.6 below.
3.3.4 Where CTs and/or VTs are used then a test terminal block or equivalent facility
shall be provided close to the meter(s). This facility will be fitted with the DNO
seals.
3.3.5 Current Transformers
(a) Two sets of CTs to IEC 60044-1 (or the standard current at the date of
design of such equipment) with a minimum standard of accuracy class
0.2 shall be provided per circuit and shall also meet (to the extent
applicable) any meter certification regulations in force at the time.
(b) Each CT secondary winding supplying a main meter shall be dedicated
to Metering purposes only. Each CT secondary winding only supplying
a check meter may be used for other purposes so long as such other uses
do not degrade the accuracy of the check meter outside the limits
required by paragraph 4.1.1 and sub-paragraph (f) below, and the DNO
is notified of such other uses in accordance with sub-paragraph (g)
below.
(c) Where a CT circuit has an additional burden not associated with meters,
this additional burden shall not be modified in any way without obtaining
the approval of the DNO in accordance with sub-paragraph (g) below.
(d) Common return leads for two or more CT secondary circuits are not
permitted.
(e) Main and check meters must be connected to different CTs.
(f) The total burden on CTs shall not exceed their rating at the rated
secondary current.
(g) Where any of the foregoing provisions of this paragraph 3.3.5 permit a
modification to CT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.5
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and also to ensure there is no degradation of the accuracy required by
paragraph 4.1.1.
3.3.6 Voltage Transformers
(a) Two VTs, or one VT with two or more secondary winding sets, to IEC
60044-2 (or the standard current at the date of design of such equipment)
with a minimum standard of accuracy class 0.5 shall be provided for the
Metering of each circuit and shall also (to the extent applicable) meet
any meter certification regulations in force at the time.
(b) Capacitor VTs shall have a working burden which provides for
monitoring of the integrity of each fuse and which does not exceed the
maximum rating or fall below the minimum rating stipulated by the
relevant manufacturer.
(c) Each VT secondary winding supplying a main meter shall be dedicated
to Metering purposes only. Each VT secondary winding only supplying
a check meter may be used for other purposes so long as other uses do
not degrade the accuracy of the check meter outside the limits required
by paragraph 4.1.1 and sub-paragraph (g) below and the DNO is notified
of such other uses in accordance with subparagraph (h) below.
(d) Where a VT circuit has an additional burden not associated with meters,
this additional burden shall not be modified in any way unless the
approval of the DNO is obtained in accordance with subparagraph (h)
below.
(e) Each meter circuit shall be fed by a separate, fused supply from the VT.
(f) Main and check meters must be connected to different VTs. If the VT
supplies other equipment, separate fusing must be provided for the
Metering.
(g) The total burden on VTs shall not exceed their rating at the rated
secondary voltages.
(h) Where any of the foregoing provisions of this paragraph 3.3.6 permit a
modification to VT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.6
and also to ensure there is no degradation of accuracy as required by
paragraph 4.1.1.
3.3.7 Existing Installations
For installations connected to the Distribution System prior to 1 January 2010,
the installed instrument transformers may be used irrespective of their accuracy
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class providing the Overall Accuracy requirements as defined in paragraph 4.1
are met and also the following:
(i) in the event of a significant alteration to the primary plant (e.g. a
switchgear change), new instrument transformers which comply with
paragraphs 3.3.5 and 3.3.6 shall be provided;
(ii) separately fused VT supplies shall be provided for each of the following:
(a) the main meters;
(b) the check meters; and
(c) any additional electrical burden.
3.4 Data Collectors
3.4.1 Data collectors may be either an integral part of individual circuit meters or
stand alone units which collect pulses from one or more individual meters.
Duplicate data collectors may also be an integral part of check meters or stand
alone units. These will be provided by the Meter Responsible Person and used
to collect, store and transmit energy values for each Settlement Period to a
DNO Data Collection System.
3.4.2 The following is required:
(a) the data collectors must have sufficient data channels to store all halfhour
value types necessary for settlement (e.g. kWh and kVArh Import
and Export per connection) and be capable of storing these values during
failure of the AC power supply;
(b) on demand from the DNO Data Collection System the data collector
will transfer the recorded Settlement Values without loss or error. The
Settlement Values must also be transferable manually using a portable
collection device (personal computer/hand held unit/removable memory
module etc) of a type compatible with the system used by the DNO; and
(c) in the event of failure of communications with the central collection
station the data collector will be capable of storing a minimum of five
channels of data per connection for a minimum period of 20 days with an
integrating period of 30 minutes. This 20 day period may reduce pro rata
dependent on the notified demand period selected as described in
paragraph 3.4.3 below. Access to the manual transfer facility will be
secured from unauthorised interference.
3.4.3 The settlement period shall be selectable over the following range: 30, 15, and 1
minutes and will be notified by the DNO. For any selectable value in this range
one Settlement Period shall commence on the hour and half-hour.
3.4.4 Monitoring facilities shall be provided for data collector fault conditions and to
record any instances of local interrogation which changes data.
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3.5 Data Collection System
3.5.1 Communications
The means of communication between the data collector and the central DNO
Data Collection System must be secure at the remote end. Communication can
be via PSTN, PTN, GPRS, GSM networks or by any other technically suitable
means which has previously been agreed with the DNO.
3.5.2 Central Collection Station
The DNO Data Collection System will interrogate each remote meter or data
collector. All the DNO operations carried out either manually or automatically
shall be protected by password protection. The DNO Data Collection System
will synchronise the outstations during interrogation to a standard reference
time. Following receipt of all data channels from the outstation the meter data
will be transferred to the DNO’s billing and settlement systems.
3.5.3 Supply Voltage
Assured Supplies must be used where ever possible. However, where a
measurement VT source is used and the outstation is storing data for more than
one circuit, a voltage selector relay scheme using each circuit involved shall be
provided. Local and remote phase failure indications shall be provided.
3.6 Facilities
The Metering equipment shall be capable of providing voltage free (clean contacts)
relay outputs which accurately represent the recorded channel values for:
(a) kWh (Import and Export) and kVArh (lagging and leading).
(b) A 30 minute reset pulse.
4 Measurement Criteria
4.1 Accuracy
4.1.1 Overall Accuracy of Equipment
Meters shall be calibrated so as to achieve Overall Accuracy of Metering within the
limits set out below. Calibration of meters shall be adjusted due to current and voltage
transformer errors and/or errors due to lead electrical burdens but not for primary
transformer losses. Paragraph 4.2.2 deals further with this issue.
(a) Active Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
120% to 10% inclusive 1.0 ±1.0%
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Below 10% to 5% inclusive
120% to 10% inclusive
1.0
0.5 lag and 0.8 lead
±1.5%
±2.0%
(b) Reactive Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
120% – 10% inclusive
120% – 20% inclusive
0
0.866 lag and lead
±4.0%
±5.0%
4.1.2 Accuracy of Time Keeping
(a) The time keeping accuracy of Metering equipment shall be maintained
in accordance with Standard Time.
(b) The commencement of each Settlement Period shall be within 10
seconds of Standard Time.
(c) The duration of each Settlement Period shall be within ± 0.1% of the
required duration, except where synchronisation has occurred in a
Settlement Period.
4.2 Compensation for Errors
4.2.1 Compensation for Instrument Transformer Errors
Compensation shall be made for errors of current and voltage transformers
and/or lead electrical burdens, if possible, in the meter calibration.
4.2.2 Compensation for Power Transformer and Line Losses
Where the installed Metering location and the Connection Point do not
coincide then, where necessary, compensation for power transformer and/or line
losses shall be provided to meet the Overall Accuracy at the boundary point
defined in paragraph 3.2.2. Compensation shall be made in the relevant data
collector and the formula for calculation shall be agreed between the DNO and
the relevant User.
4.2.3 Where existing calibration records do not exist, a recalibration test shall be
carried out where practicable. Values of compensation shall be recorded and
evidence to justify the compensation criteria shall be made available for
inspection, including all test certificates.
5 Calibration and Testing of Metering
5.1 Meters
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Metering Systems shall be calibrated and tested in accordance with the relevant part of
BS EN 62053 and the manufacturer’s recommendations.
5.2 Current and Voltage Transformers
Measuring transformers shall be supplied with known characteristics within the
requirements of paragraph 3.3 of this Sub-Code.
5.3 Test Access to Metering Equipment
Metering equipment shall be provided with sealable test terminal blocks both at the
meter and if practicable at the switchgear to facilitate meter testing and current /
voltage transformer checks in situ. Test terminal block design shall be agreed in
advance with the DNO.
5.4 Data Collectors
5.4.1 Maintenance
Data collectors must be maintained in accordance with the manufacturer’s
recommendations or as otherwise necessary to meet the obligations of this Sub-
Code.
5.4.2 Testing
There is no requirement for routine tests of data collectors other than as a part
of an overall Metering System test.
5.5 Records
The results of all tests and periodic checks shall be held as a permanent record by the
DNO and a copy held by the Generator.
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APPENDIX
LABELLING OF METERS FOR IMPORT AND EXPORT
1 ACTIVE ENERGY
Active Energy is considered to be Imported when it flows to the User System from
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Import”.
Active Energy is considered to be Exported when it flows from the User System to
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Export”.
Meters shall be labelled to distinguish between main and check meters.
2 REACTIVE ENERGY
Reactive Energy is considered to be Imported or Exported as follows:
Flow of Active Energy Power Factor Flow of Reactive Energy
Import Lagging Import*
Import Leading Export*
Import Unity Zero
Export Lagging Export
Export Leading Import
Export Unity Zero
For the purposes of labelling of meters the conditions asterisked above will determine labelling
where Import for Active Energy is defined as in 1 above.
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SUB-CODE D3
Demand Customer Connected Load or Generation 1MVA to 10MVA
Contents
1 Scope
2 Standards
3 Facilities to be provided at Metering points
3.1 General
3.2 Meters
3.3 Instrument Transformers
3.4 Data Collectors
3.5 Data Collection System
3.6 Facilities
4 Measurement criteria
4.1 Accuracy
4.2 Compensation for Errors
5 Calibration and testing of Metering
5.1 Meters
5.2 Current and Voltage Transformers
5.3 Test Access to Metering Equipment
5.4 Data Collectors
5.5 Records
Appendix
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1 Scope
1.1 This Sub-Code D3 specifies the Metering facilities which must be provided and certain
practices that must be employed for the measurement of electrical energy flows
associated with:
(a) Suppliers in relation to their Demand Customers; and
(b) Generating Units.
1.2 This Sub-Code supplements the Main Code of the Distribution Metering Code to
which reference should be made. In the event of an inconsistency between the
provisions of this Sub-Code and the Main Code, the provisions of the Main Code
shall prevail.
1.3 This Sub-Code should also be read in conjunction with any relevant Agreed
Procedures and Schedule 7 of the Order.
1.4 This Sub-Code applies to circuits with a rated capacity which exceeds 1 MVA and up
to and including 10 MVA.
1.5 For the purposes of this Sub-Code, the criteria for a Demand Customer supply
(Import Active Energy) to be over 1 MVA is that monthly maximum demand in each
of the three months of the highest maximum demand on the Distribution System in
each period of 12 consecutive months exceeds 1 MVA. For a new supply, a maximum
demand is formally agreed between the Demand Customer and the DNO and this is
periodically reviewed thereafter.
2 Standards
All references to industry standards given in the text of this Sub-Code are to versions
which are current as at 1 November 2007. However, Metering is required to comply
with the version of any such standard, equivalent or replacement which is in force at
the date of installation.
3 Facilities to be Provided at Metering Points
3.1 General
Although for clarity the specification identifies separate items of equipment, nothing in
this Sub-Code prevents the items being combined to perform the same task provided
the requirements of this Sub-Code are met.
3.2 Meters
3.2.1 For each circuit the following energy measurements are required at or in
relation to the Connection Point:-
(a) Active Energy for Import (kWh);
(b) Active Energy for Export (kWh) (applicable to Generators only);
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(c) Reactive Energy for Import and Export (kVArh).
3.2.2 The Meter Responsible Person shall ensure that Metering for the above
measurements shall normally be provided on the User’s side of the Connection
Point in order to measure required Settlement Values.
3.2.3 Active Energy Meters (kWh)
Active Energy meters shall comply with the relevant part of BSEN 60653 (or
the standard current at the date of design of such equipment) for class 0.5
meters.
3.2.4 Reactive Energy Meters (kVArh)
Reactive Energy meters shall comply with the relevant requirements of IEC
Standard 1268 or BS EN 62053 (or the standard current at the date of design of
such equipment) Part 4 for class 2 meters.
3.2.5 The measurements will be produced using the outputs from current transformers
and voltage transformers.
3.2.6 Each circuit will be provided with:-
(a) main kWh meter;
(b) check kWh meter;
(c) two main kVArh meters or one bi-directional kVArh meter for lagging
and leading power factors; and
(d) two check kVArh meters or one bi-directional kVArh meter for lagging
and leading power factors.
Paragraph 3.2.9 deals with the situation where Import and/or Export of Active
Energy is required at the same point where a single meter can be used.
3.2.7 If direct measurement of the required values cannot be achieved, then the
required values may be calculated using values measured at other points subject
to prior agreement with the DNO and providing the Overall Accuracy meets
the requirements of paragraph 4.1. Where compensation is applied the values
shall be recorded and supporting evidence shall be available to justify the
compensation criteria.
3.2.8 Where the Import and/or Export of Active Energy and Reactive Energy is
required to be measured at the same point, these functions may be combined in
a single meter in which each energy flow is measured separately.
3.2.9 Meters shall be labelled in accordance with the Appendix of this Sub-Code.
3.3 Instrument Transformers
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3.3.1 The terms “current transformer” (CT) and “voltage transformer” (VT) used in
this Sub-Code do not preclude the use of other measuring techniques providing
the accuracy, and also the longer term accuracy, in accordance with this Sub-
Code can be verified to the DNO’s satisfaction.
3.3.2 In accordance with the principles in paragraph 3.2.2, all CTs and VTs will be
fitted on the User’s side of the Connection Point except where otherwise
agreed with the DNO.
3.3.3 Where CTs and/or VTs are used, they shall meet the requirements set out in
paragraphs 3.3.5 and 3.3.6 below.
3.3.4 Where CTs and/or VTs are used then a test terminal block or equivalent facility
shall be provided close to the meter(s). This facility will be fitted with the DNO
seals.
3.3.5 Current Transformers
(a) One set of CTs to IEC 60044-1 (or the standard current at the date of
design of such equipment) with a minimum standard of accuracy class
0.5S5S shall be provided per circuit and shall also meet (to the extent
applicable) any meter certification regulations in force at the time.
(b) Each CT secondary winding circuit supplying the meters shall be
dedicated to Metering purposes only. CT secondary winding may supply
both main and check meters as long as this does not put the overall
Metering system accuracy value outside the limits defined in paragraph
4.1.1 and sub-paragraph (e) below.
(c) Where a CT circuit has an additional burden not associated with meters,
e.g. to improve system accuracy, this additional burden shall not be
modified in any way without obtaining the approval of the DNO in
accordance with sub-paragraph (f) below.
(d) Common return leads for two or more CT secondary circuits are not
permitted.
(e) The total burden on CTs shall not exceed their rating at the rated
secondary current.
(f) Where any of the foregoing provisions of this paragraph 3.3.5 permit a
modification to CT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.5
and also to ensure there is no degradation of the accuracy required by
paragraph 4.1.1.
3.3.6 Voltage Transformers
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(a) One VT to IEC 60044-2 (or the standard current at the date of design of
such equipment) with a minimum standard of accuracy class 1.00 shall
be provided for the Metering of each circuit and shall also (to the extent
applicable) meet any meter certification regulations in force at the time.
(b) Capacitor VTs shall have a working burden which provides for
monitoring of the integrity of each fuse and which does not exceed the
maximum rating or fall below the minimum rating stipulated by the
relevant manufacturer.
(c) Each VT secondary winding supplying the meters shall be dedicated to
Metering purposes only. VT secondary winding may supply both main
and check meters as long as this does not put the overall Metering
System accuracy value outside the limits defined in paragraph 4.1.1 and
subparagraph (f) below.
(d) Where a VT circuit has an additional burden not associated with meters
e.g. to improve system accuracy, this additional burden shall not be
modified in any way unless the approval of the DNO is obtained in
accordance with sub paragraph (g) below.
(e) Each meter circuit shall be fed by a separate, fused supply from the VT.
(f) The total burden on VTs shall not exceed their rating at the rated
secondary voltages.
(g) Where any of the foregoing provisions of this paragraph 3.3.6 permit a
modification to VT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.6
and also to ensure there is no degradation of accuracy as required by
paragraph 4.1.1.
3.3.7 Existing Installations
For installations connected to the Distribution System prior to 1 January 2010,
the installed instrument transformers may be used irrespective of their accuracy
class providing the Overall Accuracy requirements as defined in paragraph 4.1
are met and also the following:
(i) in the event of a significant alteration to the primary plant (e.g. a
switchgear change), new instrument transformers which comply with
paragraphs 3.3.5 and 3.3.6 shall be provided; and
(ii) separately fused VT supplies shall be provided for the main and the
check meters.
3.4 Data Collectors
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3.4.1 Data collectors may be either an integral part of individual circuit meters or
stand alone units which collect pulses from one or more individual meters.
Duplicate data collectors may also be an integral part of check meters or stand
alone units. These will be provided by the Meter Responsible Person and used
to collect, store and transmit energy values for each Settlement Period to a
DNO Data Collection System.
3.4.2 The following is required:
(a) the data collectors must have sufficient data channels to store all halfhour
value types necessary for settlement (e.g. kWh and kVArh Import
and Export per connection) and be capable of storing these values during
failure of the AC power supply;
(b) on demand from the DNO Data Collection System the data collector
will transfer the recorded Settlement Values without loss or error. The
Settlement Values must also be transferable manually using a portable
collection device (personal computer/hand held unit/removable memory
module etc) of a type compatible with the system used by the DNO; and
(c) in the event of failure of communications with the central collection
station the data collector will be capable of storing a minimum of five
channels of data per connection for a minimum period of 20 days with an
integrating period of 30 minutes. This 20 day period may reduce pro rata
dependent on the notified demand period selected as described in
paragraph 3.4.3 below. Access to the manual transfer facility will be
secured from unauthorised interference.
3.4.3 The settlement period shall be selectable over the following range: 30, 15, and 1
minutes and will be notified by the DNO. For any selectable value in this range
one Settlement Period shall commence on the hour and half-hour.
3.4.4 Monitoring facilities shall be provided for data collector fault conditions and to
record any instances of local interrogation which changes data.
3.5 Data Collection System
3.5.1 Communications
The means of communication between the data collector and the central DNO
Data Collection System must be secure at the remote end. Communication can
be via PSTN, PTN, GPRS, GSM networks or by any other technically suitable
means which has previously been agreed with the DNO.
3.5.2 Central Collection Station
The DNO Data Collection System will interrogate each remote meter or data
collector. All the DNO operations carried out either manually or automatically
shall be protected by password protection. The DNO Data Collection System
will synchronise the outstations during interrogation to a standard reference
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time. Following receipt of all data channels from the outstation the meter data
will be transferred to the DNO’s billing and settlement systems.
3.5.3 Supply Voltage
Assured Supplies must be used where ever possible. However, where a
measurement VT source is used and the outstation is storing data for more than
one circuit, a voltage selector relay scheme using each circuit involved shall be
provided. Local and remote phase failure indications shall be provided.
3.6 Facilities
The Metering equipment shall be capable of providing voltage free (clean contacts)
relay outputs which accurately represent the recorded channel values for:
(a) kWh (Import and Export) and kVArh (lagging and leading).
(b) A 30 minute reset pulse.
4 Measurement Criteria
4.1 Accuracy
4.1.1 Overall Accuracy of Equipment
Meters shall be calibrated so as to achieve Overall Accuracy of Metering
within the limits set out below. Calibration of meters shall be adjusted due to
current and voltage transformer errors and/or errors due to lead electrical
burdens but not for primary transformer losses. Paragraph 4.2.2 deals further
with this issue.
(a) Active Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
100% to 20% inclusive
Below 20% to 5% inclusive
100% to 20% inclusive
1.0
1.0
0.5 lag and 0.8 lead
±1.5%
±2.5%
±2.5%
(b) Reactive Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
100% – 20% inclusive
100% – 20% inclusive
0
0.866 lag and lead
±4.0%
±5.0%
4.1.2 Accuracy of Time Keeping
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(a) The time keeping accuracy of Metering equipment shall be maintained
in accordance with Standard Time.
(b) The commencement of each Settlement Period shall be within 10
seconds of Standard Time.
(c) The duration of each Settlement Period shall be within ± 0.1% of the
required duration, except where synchronisation has occurred in a
Settlement Period.
4.2 Compensation for Errors
4.2.1 Compensation for Instrument Transformer Errors
Compensation shall be made for errors of current and voltage transformers
and/or lead electrical burdens, if possible, in the meter calibration.
4.2.2 Compensation for Power Transformer and Line Losses
Where the installed Metering location and the Connection Point do not
coincide then, where necessary, compensation for power transformer and/or line
losses shall be provided to meet the Overall Accuracy at the boundary point
defined in paragraph 3.2.2. Compensation shall be made in the relevant data
collector and the formula for calculation shall be agreed between the DNO and
the relevant User.
4.2.3 Where existing calibration records do not exist, a recalibration test shall be
carried out where practicable. Values of compensation shall be recorded and
evidence to justify the compensation criteria shall be made available for
inspection, including all test certificates.
5 Calibration and Testing of Metering
5.1 Meters
Metering Systems shall be calibrated and tested in accordance with the relevant part of
BS EN 62053 and the manufacturer’s recommendations.
5.2 Current and Voltage Transformers
Measuring transformers shall be supplied with known characteristics within the
requirements of paragraph 3.3 of this Sub-Code.
5.3 Test Access to Metering Equipment
Metering equipment shall be provided with sealable test terminal blocks both at the
meter and if practicable at the switchgear to facilitate meter testing and current /
voltage transformer checks in situ. Test terminal block design shall be agreed in
advance with the DNO.
5.4 Data Collectors
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5.4.1 Maintenance
Data collectors must be maintained in accordance with the manufacturer’s
recommendations or as otherwise necessary to meet the obligations of this Sub-
Code.
5.4.2 Testing
There is no requirement for routine tests of data collectors other than as a part
of an overall Metering System test.
5.5 Records
The results of all tests and periodic checks shall be held as a permanent record by the
DNO and a copy held by the Generator.
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APPENDIX
LABELLING OF METERS FOR IMPORT AND EXPORT
1 ACTIVE ENERGY
Active Energy is considered to be Imported when it flows to the User System from
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Import”.
Active Energy is considered to be Exported when it flows from the User System to
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Export”.
Meters shall be labelled to distinguish between main and check meters.
2 REACTIVE ENERGY
Reactive Energy is considered to be Imported or Exported as follows:
Flow of active Energy Power Factor Flow of Reactive Energy
Import Lagging Import*
Import Leading Export*
Import Unity Zero
Export Lagging Export
Export Leading Import
Export Unity Zero
For the purposes of labelling of meters the conditions asterisked above will determine
labelling where Import for Active Energy is defined as in 1 above.
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SUB-CODE D4
Demand Customer Connected Load or Generation 70 kVA to 1MVA
Contents
1 Scope
2 Standards
3 Facilities to be provided at Metering points
3.1 General
3.2 Meters
3.3 Instrument Transformers
3.4 Data Collectors
3.5 Data Collection System
3.6 Facilities
4 Measurement criteria
4.1 Accuracy
4.2 Compensation for Errors
5 Calibration and testing of Metering
5.1 Meters
5.2 Current and Voltage Transformers
5.3 Test Access to Metering Equipment
5.4 Data Collectors
5.5 Records
Appendix
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1 Scope
1.1 This Sub-Code D4 specifies the Metering facilities which must be provided and certain
practices that must be employed for the measurement of electrical energy flows
associated with:
(a) Suppliers in relation to their Demand Customers; and
(b) Generating Units.
1.2 This Sub-Code supplements the Main Code of the Distribution Metering Code to
which reference should be made. In the event of an inconsistency between the
provisions of this Sub-Code and the Main Code, the provisions of the Main Code
shall prevail.
1.3 This Sub-Code should also be read in conjunction with any relevant Agreed
Procedures and Schedule 7 of the Order.
1.4 This Sub-Code applies to circuits with a rated capacity which exceeds 70 kVA and up
to and including 1 MVA.
1.5 For the purposes of this Sub-Code, the criteria for a Demand Customer supply
(Import Active Energy) to be over 70 kVA is that monthly maximum demand in each
of the three months of the highest maximum demand on the Distribution System in
each period of 12 consecutive months exceeds 70 kVA. For a new supply, a maximum
demand is formally agreed between the Demand Customer and the DNO and this is
periodically reviewed thereafter.
2 Standards
All references to industry standards given in the text of this Sub-Code are to versions
which are current as at1 November 2007. However, Metering is required to comply
with the version of any such standard, equivalent or replacement which is in force at
the date of installation.
3 Facilities to be Provided at Metering Points
3.1 General
Although for clarity the specification identifies separate items of equipment, nothing in
this Sub-Code prevents the items being combined to perform the same task provided
the requirements of this Sub-Code are met.
3.2 Meters
3.2.1 For each circuit the following energy measurements are required at or in
relation to the Connection Point:-
(a) Active Energy for Import (kWh);
(b) Active Energy for Export (kWh) (applicable to Generators only);
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(c) Reactive Energy for Import and Export (kVArh).
3.2.2 The Meter Responsible Person shall ensure that Metering for the above
measurements shall normally be provided on the User’s side of the Connection
Point in order to measure required Settlement Values.
3.2.3 Active Energy Meters (kWh)
Active Energy meters shall comply with the relevant part of BS EN 62053 (or
the standard current at the date of design of such equipment) for class 2 meters.
3.2.4 Reactive Energy Meters (kVArh)
Reactive Energy meters shall comply with the relevant requirements of IEC
Standard 1268 or BS EN 62053 (or the standard current at the date of design of
such equipment) Part 4 for class 3 meters.
3.2.5 The measurements will be produced using the outputs from current transformers
and voltage transformers.
3.2.6 Each circuit will be provided with:-
(a) main kWh meter; and
(b) two main kVArh meters or one bi-directional kVArh meter for lagging
and leading power factors;
Paragraph 3.2.9 deals with the situation where Import and/or Export of Active
Energy is required at the same point where a single meter can be used.
3.2.7 If direct measurement of the required values cannot be achieved, then the
required values may be calculated using values measured at other points subject
to prior agreement with the DNO and providing the Overall Accuracy meets
the requirements of paragraph 4.1. Where compensation is applied the values
shall be recorded and supporting evidence shall be available to justify the
compensation criteria.
3.2.8 Where the Import and/or Export of Active Energy and Reactive Energy is
required to be measured at the same point, these functions may be combined in
a single meter in which each energy flow is measured separately.
3.2.9 Meters shall be labelled in accordance with the Appendix of this Sub-Code.
3.3 Instrument Transformers
3.3.1 The terms “current transformer” (CT) and “voltage transformer” (VT) used in
this Sub-Code do not preclude the use of other measuring techniques providing
the accuracy, and also the longer term accuracy, in accordance with this Sub-
Code can be verified to the DNO’s satisfaction.
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3.3.2 In accordance with the principles in paragraph 3.2.2, all CTs and VTs will be
fitted on the User’s side of the Connection Point except where otherwise
agreed with the DNO.
3.3.3 Where CTs and/or VTs are used, they shall meet the requirements set out in
paragraphs 3.3.5 and 3.3.6 below.
3.3.4 Where CTs and/or VTs are used then a test terminal block or equivalent facility
shall be provided close to the meter(s). This facility will be fitted with the DNO
seals.
3.3.5 Current Transformers
(a) One set of CTs to IEC 60044-1 (or the standard current at the date of
design of such equipment) with a minimum standard of accuracy class
0.5S shall be provided per circuit and shall also meet (to the extent
applicable) any meter certification regulations in force at the time.
(b) Each CT secondary winding circuit supplying the meters shall be
dedicated to Metering purposes only. CT secondary winding may supply
both main and check meters as long as this does not put the overall
Metering system accuracy value outside the limits defined in paragraph
4.1.1 and sub-paragraph (e) below.
(c) Where a CT circuit has an additional burden not associated with meters,
e.g. to improve system accuracy, this additional burden shall not be
modified in any way without obtaining the approval of the DNO in
accordance with sub-paragraph (f) below.
(d) Common return leads for two or more CT secondary circuits are not
permitted.
(e) The total burden on CTs shall not exceed their rating at the rated
secondary current.
(f) Where any of the foregoing provisions of this paragraph 3.3.5 permit a
modification to CT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.5
and also to ensure there is no degradation of the accuracy required by
paragraph 4.1.1.
3.3.6 Voltage Transformers
(a) One VT to IEC 60044-2 (or the standard current at the date of design of
such equipment) with a minimum standard of accuracy class 11 shall be
provided for the Metering of each circuit and shall also (to the extent
applicable) meet any meter certification regulations in force at the time.
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(b) Capacitor VTs shall have a working burden which provides for
monitoring of the integrity of each fuse and which does not exceed the
maximum rating or fall below the minimum rating stipulated by the
relevant manufacturer.
(c) Each VT secondary winding supplying the meters shall be dedicated to
Metering purposes only. VT secondary winding may supply both main
and check meters as long as this does not put the overall Metering
System accuracy value outside the limits defined in paragraph 4.1.1 and
subparagraph (f) below.
(d) Where a VT circuit has an additional burden not associated with meters
e.g. to improve system accuracy, this additional burden shall not be
modified in any way unless the approval of the DNO is obtained in
accordance with sub paragraph (g) below.
(e) Each meter circuit shall be fed by a separate, fused supply from the VT.
(f) The total burden on VTs shall not exceed their rating at the rated
secondary voltages.
(g) Where any of the foregoing provisions of this paragraph 3.3.6 permit a
modification to VT secondary circuits, provided that the approval of the
DNO is sought for the modification, any such request must be made in
writing to the DNO a reasonable time in advance of the modification and
evidence of the value of any additional electrical burden must be made
available for inspection to verify compliance with this paragraph 3.3.6
and also to ensure there is no degradation of accuracy as required by
paragraph 4.1.1.
3.3.7 Existing Installations
For installations connected to the Distribution System prior to 1 January 2010,
the installed instrument transformers may be used irrespective of their accuracy
class providing the Overall Accuracy requirements as defined in paragraph 4.1
are met and also the following:
(i) in the event of a significant alteration to the primary plant (e.g. a
switchgear change), new instrument transformers which comply with
paragraphs 3.3.5 and 3.3.6 shall be provided; and
(ii) separately fused VT supplies shall be provided for the main and the
check meters.
3.4 Data Collectors
3.4.1 Data collectors may be either an integral part of individual circuit meters or
stand alone units which collect pulses from one or more individual meters.
Duplicate data collectors may also be an integral part of check meters or stand
alone units. These will be provided by the Meter Responsible Person and used
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to collect, store and transmit energy values for each Settlement Period to a
DNO Data Collection System.
3.4.2 The following is required:
(a) the data collectors must have sufficient data channels to store all halfhour
value types necessary for settlement (e.g. kWh and kVArh Import
and Export per connection) and be capable of storing these values during
failure of the AC power supply;
(b) on demand from the DNO Data Collection System the data collector
will transfer the recorded Settlement Values without loss or error. The
Settlement Values must also be transferable manually using a portable
collection device (personal computer/hand held unit/removable memory
module etc) of a type compatible with the system used by the DNO; and
(c) in the event of failure of communications with the central collection
station the data collector will be capable of storing a minimum of five
channels of data per connection for a minimum period of 20 days with an
integrating period of 30 minutes. This 20 day period may reduce pro rata
dependent on the notified demand period selected as described in
paragraph 3.4.3 below. Access to the manual transfer facility will be
secured from unauthorised interference.
3.4.3 The settlement period shall be selectable over the following range: 30, 15, and 1
minutes and will be notified by the DNO. For any selectable value in this range
one Settlement Period shall commence on the hour and half-hour.
3.4.4 Monitoring facilities shall be provided for data collector fault conditions and to
record any instances of local interrogation which changes data.
3.5 Data Collection System
3.5.1 Communications
The means of communication between the data collector and the central DNO
Data Collection System must be secure at the remote end. Communication can
be via PSTN, PTN, GPRS, GSM networks or by any other technically suitable
means which has previously been agreed with the DNO.
3.5.2 Central Collection Station
The DNO Data Collection System will interrogate each remote meter or data
collector. All the DNO operations carried out either manually or automatically
shall be protected by password protection. The DNO Data Collection System
will synchronise the outstations during interrogation to a standard reference
time. Following receipt of all data channels from the outstation the meter data
will be transferred to the DNO’s billing and settlement systems.
3.5.3 Supply Voltage
Distribution Code 1 May 2010
The Distribution Metering Code Page 162
Assured Supplies must be used where ever possible. However, where a
measurement VT source is used and the outstation is storing data for more than
one circuit, a voltage selector relay scheme using each circuit involved shall be
provided. Local and remote phase failure indications shall be provided.
3.6 Facilities
The Metering equipment shall be capable of providing voltage free (clean contacts)
relay outputs which accurately represent the recorded channel values for:-
(a) kWh (Import and Export) and kVArh (lagging and leading).
(b) A 30 minute reset pulse
4 Measurement Criteria
4.1 Accuracy
4.1.1 Overall Accuracy of Equipment
Meters shall be calibrated so as to achieve Overall Accuracy of Metering within
the limits set out below. Calibration of meters shall be adjusted due to current
and voltage transformer errors and/or errors due to lead electrical burdens but
not for primary transformer losses. Paragraph 4.2.2 deals further with this
issue.
(a) Active Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
100% to 20% inclusive
Below 20% to 5% inclusive
100% to 20% inclusive
1.0
1.0
0.5 lag and 0.8 lead
±1.5%
±2.5%
±2.5%
(b) Reactive Energy Measurement
Conditions of Test Limits of Error at Power Factor
Current expressed as a percentage of rated
measuring current
Power Factor Limits of Error
100% – 20% inclusive
100% – 20% inclusive
0
0.866 lag and lead
±4.0%
±5.0%
4.1.2 Accuracy of Time Keeping
(a) The time keeping accuracy of Metering equipment shall be maintained
in accordance with Standard Time.
(b) The commencement of each Settlement Period shall be within 10
seconds of Standard Time.
Distribution Code 1 May 2010
The Distribution Metering Code Page 163
(c) The duration of each Settlement Period shall be within ± 0.1% of the
required duration, except where synchronisation has occurred in a
Settlement Period.
4.2 Compensation for Errors
4.2.1 Compensation for Instrument Transformer Errors
Compensation shall be made for errors of current and voltage transformers
and/or lead electrical burdens, if possible, in the meter calibration.
4.2.2 Compensation for Power Transformer and Line Losses
Where the installed Metering location and the Connection Point do not
coincide then, where necessary, compensation for power transformer and/or line
losses shall be provided to meet the Overall Accuracy at the boundary point
defined in paragraph 3.2.2. Compensation shall be made in the relevant data
collector and the formula for calculation shall be agreed between the DNO and
the relevant User.
4.2.3 Where existing calibration records do not exist, a recalibration test shall be
carried out where practicable. Values of compensation shall be recorded and
evidence to justify the compensation criteria shall be made available for
inspection, including all test certificates.
5 Calibration and Testing of Metering
5.1 Meters
Metering Systems shall be calibrated and tested in accordance with the relevant part of
BS EN 62053 and the manufacturer’s recommendations.
5.2 Current and Voltage Transformers
Measuring transformers shall be supplied with known characteristics within the
requirements of paragraph 3.3 of this Sub-Code.
5.3 Test Access to Metering Equipment
Metering equipment shall be provided with sealable test terminal blocks both at the
meter and if practicable at the switchgear to facilitate meter testing and current /
voltage transformer checks in situ. Test terminal block design shall be agreed in
advance with the DNO.
5.4 Data Collectors
5.4.1 Maintenance
Data collectors must be maintained in accordance with the manufacturer’s
recommendations or as otherwise necessary to meet the obligations of this Sub-
Code.
Distribution Code 1 May 2010
The Distribution Metering Code Page 164
5.4.2 Testing
There is no requirement for routine tests of data collectors other than as a part
of an overall Metering System test.
5.5 Records
The results of all tests and periodic checks shall be held as a permanent record by the
DNO and a copy held by the Generator.
Distribution Code 1 May 2010
The Distribution Metering Code Page 165
APPENDIX
LABELLING OF METERS FOR IMPORT AND EXPORT
1 ACTIVE ENERGY
Active Energy is considered to be Imported when it flows to the User System from
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Import”.
Active Energy is considered to be Exported when it flows from the User System to
the Distribution System. The meter(s) registering this Active Energy should be
labelled “Export”.
Meters shall be labelled to distinguish between main and check meters.
2 REACTIVE ENERGY
Reactive Energy is considered to be Imported or Exported as follows:
Flow of active Energy Power Factor Flow of Reactive Energy
Import Lagging Import*
Import Leading Export*
Import Unity Zero
Export Lagging Export
Export Leading Import
Export Unity Zero
For the purposes of labelling of meters the conditions asterisked above will determine labelling
where Import for Active Energy is defined as in 1 above.
Distribution Code 1 May 2010
The Distribution Metering Code Page 166
Agreed Procedure No. 1
MAINTENANCE, TESTING, INSPECTION AND SEALING OF
METERING AND GENERATOR METERING CIRCUITS
for the electricity industry in
Northern Ireland
Distribution Code 1 May 2010
The Distribution Metering Code Page 167
AGREED PROCEDURE No. 1
MAINTENANCE, TESTING , INSPECTION AND SEALING OF METERING AND
GENERATOR METERING CIRCUITS
Contents
1 Scope of Procedure
2 Use of the Procedure
3 Amendments to Forms
4 Interface and Timetable Information
Appendix A – Request to Break Seals Form
Appendix B – Meter Record Sheet
Distribution Code 1 May 2010
The Distribution Metering Code Page 168
1 SCOPE OF PROCEDURE
1.1 This Agreed Procedure (the “Procedure”) outlines the responsibilities of the DNO and
the Generator with regard to notification, authorisation and witnessing of the breaking
and replacement of seals on generation Metering and Generator Metering Circuits and
the carrying out of routine and emergency maintenance, testing and calibration. The
procedure assumes the initial placement of seals by the appropriate Parties in
accordance with the Main Code.
1.2 The Procedure supplements the Main Code and the Sub-Codes of the Distribution
Metering Code to which reference should be made. In the event of an inconsistency
between the provisions of the Procedure and the Main Code or a Sub-Code the
provisions of the Main Code or such Sub-Code shall prevail. The provisions of the
Main Code shall prevail over the provisions of any Sub-Code.
1.3 The Procedure is part of the Distribution Code and terms and expressions defined in the
Distribution Code have the same meaning in the Procedure.
2 USE OF THE PROCEDURE
2.1 The Procedure is to be used by the DNO and Generator staff to ensure that the breaking
and replacement of seals and the carrying out of routine and emergency maintenance,
testing and calibration on generation Metering and Generator Metering Circuits is
correctly authorised and witnessed and that documentary evidence is available to that
effect.
2.2 Where it is not possible to gain prior authorisation for the breaking of a seal
necessitated by malfunctioning of both main and check meters on a circuit, fire or
similar hazard or non-compliance by a party with its obligations under the Main Code
authorisation should be sought as soon as possible after the event.
3 AMENDMENTS TO FORMS
3.1 Forms set out in the Appendices to this Procedure may be amended from time to time
by the DNO upon reasonable notice to all Generators. The DNO shall also take into
account reasonable comments of Generators.
Distribution Code 1 May 2010
The Distribution Metering Code Page 169
4. INTERFACE AND TIMETABLE INFORMATION
Section: MAINTENANCE, TESTING AND INSPECTION OF METERING AND GENERATOR METERING CIRCUITS
Subject: Interface and Timetable Information – Maintenance, Testing, Inspection, Calibration and Sealing of Metering
REF WHEN ACTION FROM/BY TO METHOD
EITHER:
1a Routine Inspection, Maintenance, Testing & Calibration
At least 5 days
prior to carrying
work out
Notify date, time, work required, estimated duration and request
breaking of seals (as necessary)
DNO or
Generator
Generator
or DNO
Fax on standard
form (Appendix A)
OR:
1b Inspection, Maintenance, Testing and Calibration in an Emergency
At the earliest
opportunity
Notify, date, time, place, work required, estimated duration and
request breaking of seals (as necessary)
DNO or
Generator
Generator
or DNO
Fax on standard
form (Appendix A)
or verbally
2 Prior to work being
carried out (Note 1)
Grant permission to break seals (as appropriate) and notify as to
attendance
Generator
or DNO
DNO or
Generator
Fax on standard
form (Appendix A)
or verbally
3 Day work carried
out
Record meter readings prior to seals being broken and
commencing work
DNO or
Nominated
Party
Manual record
(Appendix B)
Distribution Code 1 May 2010
The Distribution Metering Code Page 170
4. INTERFACE AND TIMETABLE INFORMATION
Section: MAINTENANCE, TESTING AND INSPECTION OF METERING AND GENERATOR METERING CIRCUITS
Subject: Interface and Timetable Information – Maintenance, Testing, Inspection, Calibration and Sealing of Metering
REF WHEN ACTION FROM/BY TO METHOD
4a Day work carried
out
Carry out required work. Record details of work done DNO or
Generator
Manual record
(Appendix A)
4b Where possible Witness work being carried out Generator
or DNO
5 After work
completed
Apply own seals and read meters DNO and
Generator
6 After work
completed
Check accuracy of manual record and sign to confirm work
completed and seal applied
DNO and
Generator
Manual record
(Appendix A)
7 After work
completed
Record meter readings DNO or
Generator
Manual record
(Appendix B)
Distribution Code 1 May 2010
The Distribution Metering Code Page 171
4. INTERFACE AND TIMETABLE INFORMATION
Section: MAINTENANCE, TESTING AND INSPECTION OF METERING AND GENERATOR METERING CIRCUITS
Subject: Interface and Timetable Information – Maintenance, Testing, Inspection, Calibration and Sealing of Metering
REF WHEN ACTION FROM/BY TO METHOD
8 After work
completed
Copy meter record sheet and work sheet and issue to other
party
DNO or
Generator
Generator
or DNO
By hand
Note 1 In an emergency situation when it is impossible to contact the DNO or the Generator, it may be necessary to break seals prior to the granting
of permission. An emergency situation is defined by the Main Code as when “both main and check meters are malfunctioning or there occurs a fire
or other similar hazard and such removal (of seals) is essential”. In such circumstances fax or other communication of the intent to break seals will
be supplied to the DNO or Generator prior to the commencement of emergency work. The authorisation procedure to break seals must be followed
retrospectively. In an emergency situation when it is impossible to await the required paperwork, verbal consent may be given. In such
circumstances written consent must follow forthwith.
Distribution Code 1 May 2010
The Distribution Metering Code Page 172
APPENDIX A
TO: [DNO/Generator] Date: [ ]
Tel: [ ]
Fax: [ ]
GENERATOR: SERIAL NO:
DETAILS OF WORK TO BE CARRIED OUT:
We request permission to carry out the work described below and to break such seals as are
necessary. We estimate the duration of the work to be from [ ] to [ ]. The
work is to be carried out at [Site] by [ ].
The description of the work is as follows:
The circuits and meters to be affected are as follows:-
CIRCUIT/METER ID COMMENTS
FROM:
Name Signature____________________________
Position Date________________________________
Continued ………
REQUEST TO BREAK SEALS
Distribution Code 1 May 2010
The Distribution Metering Code Page 173
COMMENTS OF RECIPIENTS:
We acknowledge receipt of your request dated [ ]. We hereby [give/withhold]* consent. Our
reasons for withholding consent are [ ].
Our representative dealing with sealing is [ ]. He will/will not be attending when the
work is carried out.
BY:
Name Signature_________________________
Position Date______________________________
CONFIRM COMPLETION OF WORK AND SEALS APPLIED:
DESCRIPTION OF COMPLETEDWORK:
CONFIRMATION OF SEALING:
(DNO)
Name Signature
Position Date
(GENERATOR)
Name Signature
Position Date
[* Delete as appropriate]
Distribution Code 1 May 2010
The Distribution Metering Code Page 174
SHEET: OF
SERIAL NO:
APPENDIX B
METER RECORD SHEET
GENERATOR :
READING DATE :
SITE NAME :
READING TIMES : START :
METER ID : FINISH :
FUNCTION
MAIN METER CHECK METER
BEFORE AFTER BEFORE AFTER
MWh EXPORT
MWh IMPORT
MVAr EXPORT
MVAr IMPORT
RECORDER GENERATORWITNESS
NAME
SIGNATURE
DATE
COMPANY
ACTING FOR
Distribution Code 1 May 2010
The Distribution Metering Code Page 175
Agreed Procedure No. 2
MAINTENANCE, TESTING, INSPECTION AND SEALING
OF METERING
(DEMAND CUSTOMER)
for the electricity industry in
Northern Ireland
Distribution Code 1 May 2010
The Distribution Metering Code Page 176
AGREED PROCEDURE No. 2
MAINTENANCE, TESTING, INSPECTION AND SEALING OF METERING
(DEMAND CUSTOMER)
Contents
1 Scope of Procedure
2 Use of the Procedure
3 Amendments to Forms
4 Interface and Timetable Information
Appendix A – Guide to Use of AP2 Forms
Form MT1/1
Form MT1/2
Form MT2
Distribution Code 1 May 2010
The Distribution Metering Code Page 177
SCOPE OF PROCEDURE
1.1 This Agreed Procedure (the “Procedure”) outlines the responsibilities of the DNO and
the Meter Responsible Person with regard to notification, authorisation and witnessing
of the breaking and replacement of seals on Demand Customer Metering and the
carrying out of routine and emergency maintenance, testing and calibration. The
Procedure assumes the initial placement of seals by the appropriate Parties in
accordance with paragraph 9.6 in the Main Code.
1.2 The Procedure supplements the Main Code and the Sub-Codes of the Metering Code to
which reference should be made. In the event of an inconsistency between the
provisions of the Procedure and the Main Code or a Sub-Code the provisions of the
Main Code or such Sub-Code shall prevail. The provisions of the Main Code shall
prevail over the provisions of any Sub-Code.
1.3 The Procedure is part of the Distribution Code and terms and expressions defined in the
Distribution Code have the same meaning in the Procedure.
2 USE OF THE PROCEDURE
2.1 The Procedure is to be used by the DNO and the Meter Responsible Person to ensure
that the breaking and replacement of seals and the carrying out of routine and
emergency maintenance, testing and calibration on Demand Customer Metering is
correctly authorised and witnessed and that documentary evidence is available to that
effect.
2.2 Where it is not possible to gain prior authorisation for the breaking of a seal in the
event of an emergency as described in paragraph 9.6(d)d of the Main Code or noncompliance
by a party with its obligations under the Main Code, authorisation should
be sought as soon as possible after the event.
2.3 A record of work and inspections carried out must be maintained in accordance with
paragraph 9.5 of the Main Code.
2.4 Throughout this Procedure, timetables reflect the number of Business Days (BD) before
or after which (as the case may be) an activity should be completed.
3 AMENDMENTS TO FORMS
3.1 Forms set out in the Appendices to this Procedure may be amended from time to time
by the DNO upon reasonable notice to all relevant Parties. The DNO shall also take
into account reasonable comments of relevant Parties.
Distribution Code 1 May 2010
The Distribution Metering Code Page 178
4. INTERFACE AND TIMETABLE INFORMATION
Section: MAINTENANCE, TESTING, INSPECTION AND SEALING OF METERING (DEMAND CUSTOMER)
Subject: Interface and Timetable Information – Maintenance, Testing, Inspection, Calibration and Sealing of Metering.
REF WHEN ACTION FROM/BY TO METHOD
EITHER:
1a Routine Inspection, Maintenance, Testing & Calibration
At least 15 BD
prior to carrying
work out
Notify date, time, work required, estimated
duration and request breaking of seals (as
necessary)
DNO or Meter
Responsible
Person
Meter
Responsible
Person or DNO
Fax / Post on standard
form MT1/1
OR:
1b. Inspection, Maintenance, Testing and Calibration in an Emergency
At the earliest
opportunity
Notify, date, time, place, work required,
estimated duration and request breaking of
seals (as necessary)
DNO or Meter
Responsible
Person
Meter
Responsible
Person or DNO
Fax / Post on standard
form MT1/1 or verbally
Prior to work being
carried out
Acknowledge receipt of request to break
seals and confirm attendance of party
representative
Meter
Responsible
Person or DNO
DNO or Meter
Responsible
Person
Fax / Post on standard
form MT1/2
3a. Day work carried
out
Record meter readings prior to seals being
broken and commencing work
DNO or Meter
Responsible
Person
Manual record on
standard form MT2
3b. Where possible Witness recording of meter readings DNO or Meter
Responsible
Person
Distribution Code 1 May 2010
The Distribution Metering Code Page 179
4. INTERFACE AND TIMETABLE INFORMATION
Section: MAINTENANCE, TESTING, INSPECTION AND SEALING OF METERING (DEMAND CUSTOMER)
Subject: Interface and Timetable Information – Maintenance, Testing, Inspection, Calibration and Sealing of Metering.
REF WHEN ACTION FROM/BY TO METHOD
4a. Day work carried
out
Carry out required work. Record details of
work done.
DNO or Meter
Responsible
Person
Manual record on
standard form MT1/2
4b. Where possible Witness work being carried out Meter
Responsible
Person or DNO
5a. After work
completed
Apply seals and then record meter readings. DNO or Meter
Responsible
Person
Manual record on
standard form MT2
5b. Where possible Witness recording of meter readings and
application of seals
DNO or Meter
Responsible
Person
After work
completed
Check accuracy of manual record and sign
to confirm work completed and seal applied
DNO and Meter
Responsible
Person
Standard form MT1/2
After work
completed
Copy meter record sheet and work sheet
and issue to other party
DNO or Meter
Responsible
Person
Meter
Responsible
Person or DNO
By hand
Distribution Code 1 May 2010
The Distribution Metering Code Page 180
APPENDIX A
GUIDE TO USE OF AP2 FORMS
AP2 Description Use Form
4.1a/b DNO or Meter Responsible Person give notification of work
to be carried out /completed on Metering.
MT1 / 1
DNO or Meter Responsible Person acknowledge receipt of
form MT1/1 and confirm attendance of representative
during work.
MT1 / 2
4.3a, 4.5a Record of meter readings before and after doing work MT2
4.4a, 4.6 Record of work done in relation to metering MT1 / 2
For forms completed by the Meter Responsible Person, please fax or post to the following address:
NIE plc (Attn: Manager, Customer Service Revenue)
Malone Road
Belfast BT9 5HT
FAX NO: 01232 689280
or such other address and /or recipient as the DNO may notify from time to time.
Distribution Code 1 May 2010
The Distribution Metering Code Page 181
Serial No………………
Page 1 of 2
MT1/1
NOTIFICATION OF WORK TO BE CARRIED OUT/COMPLETED
TO: (DNO/METER
RESPONSIBLE PERSON)*
SITE NAME:
DNO CRN:
METERING ID:
DETAILS OF WORK TO BE CARRIED OUT:
Notification is hereby given to carry out work described below and to break such seals as are
necessary on:-
Date:
We estimate the duration of work to be:- Start Time:
Stop Time:
The work is to be carried out at site by:
The description of the work is as follows:
The circuits and meters to be affected are as follows:-
CIRCUIT/METER SER NO. COMMENTS
FROM: (DNO/METER RESPONSIBLE PERSON)*
Name: Signature:
Position Date:
(* Delete as appropriate)
Distribution Code 1 May 2010
The Distribution Metering Code Page 182
Continued….
Serial No………………
Page 2 of 2
MT1/2
COMMENTS OF RECIPIENTS:
We acknowledge receipt of your notification dated:
Our representative is:
and (will/will not)* be attending when the work is carried out.
FROM: (DNO/METER RESPONSIBLE PERSON)*
Name: Signature:
Position Date:
CONFIRM COMPLETION OF WORK AND SEALS APPLIED:
Description of completed work:
Confirmation of sealing:
Date of work:
Time work commenced:
Time work completed:
FOR DNO:
Name: Signature:
Position Date:
FOR METER RESPONSIBLE PERSON:
Name: Signature:
Position Date:
(* Delete as appropriate)
Distribution Code 1 May 2010
The Distribution Metering Code Page 183
Serial No ………………..
Page of
MT2
METER READINGS RECORD SHEET
For multiple feeder sites use additional sheets.
METER
RESPONSIBLE
PERSON:
READING DATE:
SITE NAME: READING TIMES: START:
FINISH:
METERING ID: METER SERIAL
NO(S):
FUNCTION MAIN METER READING CHECK METER READING
BEFORE AFTER BEFORE AFTER
kWh EXPORT
2kWh IMPORT
kVArh EXPORT
kVArh IMPORT
PARTY RECORDING PARTYWITNESSING
NAME
SIGNATURE
DATE
POSITION
COMPANY
Distribution Code 1 May 2010
Agreed Procedure No. 3
METER ADVANCE RECONCILIATION
(HALF HOUR METERED GENERATION)
for the electricity industry in
Northern Ireland
Distribution Code 1 May 2010
AGREED PROCEDURE No. 3
METER ADVANCE RECONCILIATION (GENERATION)
Contents
1 Scope of Procedure
2 Use of the Procedure
3 Amendments to Proformas and Examples
4 Interface and Timetable Information
Appendix A: Proforma of Meter Advance Reconciliation – Notice of Meter Reading
Appendix B: Proforma of Meter Advance Reconciliation Record
Appendix C: Example of Meter Register Comparison Report
Appendix D: Proforma of Meter Advance Reconciliation Statement
Distribution Code 1 May 2010
1 SCOPE OF THE AGREED PROCEDURE
1.1 This Agreed Procedure (the “Procedure”) covers the collection and processing of tariff
meter readings which are taken quarterly pursuant to paragraph 9.7 of the Main Code
and the reconciliation of such meter readings with Settlement Values collected
electronically and stored on the DNO Data Collection System. This reconciliation is
achieved by comparing the manually read meter register readings with the
accumulations recorded in the DNO Data Collection System. Any discrepancies
discovered will be processed in accordance with the Trading & Settlement Code.
1.2 The Procedure seeks to ensure that any discrepancy between tariff meter register
readings and Settlement Values collected electronically from such meters is identified
on a regular basis such that appropriate adjustments to payments can be made.
1.3 The Procedure supplements the Main Code and the Sub-Codes of the Metering Code to
which reference should be made. In the event of an inconsistency between the
provisions of the Procedure and the Main Code or a Sub-Code the provisions of the
Main Code or such Sub-Code shall prevail. The provisions of the Main Code shall
prevail over the provisions of any Sub-Code.
1.4 The Procedure is part of the Distribution Code and terms and expressions defined in the
Distribution Code have the same meaning in the Procedure.
1.5 This Procedure applies to half hour metered Generators only. The meter advance
reconciliation procedures for Demand Customers are covered by Retail Market
Procedure MP NI 105.
2 USE OF THE PROCEDURE
2.1 The Procedure shall be used by the DNO and staff of those Generators who are metered
on a half-hourly basis who are responsible for meter advance reconciliation readings
and processing.
3 AMENDMENTS TO PROFORMAS AND EXAMPLES
3.1 Proformas and examples set out in the Appendices to this Procedure may be amended
from time to time by the DNO upon reasonable notice to all Generators. The DNO
shall also take into account reasonable comments of Generators.
Distribution Code 1 May 2010
4 INTERFACE AND TIMETABLE INFORMATION
Section: METER ADVANCE RECONCILIATION (GENERATION)
Subject: Interface and Timetable Information – Reconciliation of Meter Readings with Accumulated Settlement Values
REF WHEN ACTION FROM/B
Y
TO METHOD
1 Annually For each calendar month draw up a plan of the meter
readings which are to take place and issue to the
Generator. Such readings to be scheduled at intervals
not exceeding 3 months.
DNO Generator Fax
2 At least 5 days
before reading
date
Advise the Generator of date and time for reading to take
place
DNO Generator Fax on standard
form (Appendix
A)
3 Within 3 months
of last reading
Read meter registers (in the presence of the Generator
representative if attending) as close as is practicable to
the end of a Settlement Period. Record time and date of
reading and meter register values. The DNO and
Generator representative sign record sheet. (Note 1)
DNO and
Generator
Manual record
(Appendix B)
4 Before leaving
site
Sign off and hand copy of actual meter values with time
and date of reading to the Generator.
DNO Generator Manual record
(Appendix B)
Distribution Code 1 May 2010
Section: METER ADVANCE RECONCILIATION (GENERATION)
Subject: Interface and Timetable Information – Reconciliation of Meter Readings with Accumulated Settlement Values
REF WHEN ACTION FROM/B
Y
TO METHOD
5 Within 3
Business Days of
meter reading
(i) Input meter register values, time and date of
reading to the meter register comparison process
of the DNO Data Collection System
(ii) Run meter register comparison process which
compares the difference between the latest
actual and the previous actual reading with the
electronically recorded total delivered energy for
the known time interval
(iii) Print out meter register comparison report
(Appendix C)
DNO Generator On line entry to
the DNO Data
Collection
System
EITHER:
6a Within 5
Business Days of
meter reading
Where the relevant meter register comparison report
shows a difference of less than 0.02%:
– issue copy of report to the Generator (Note 2)
DNO Generator Fax
OR:
6b Within 5
Business Days of
meter reading
Where meter register comparison report shows a
difference of 0.02% or greater:
– prepare a Meter Reconciliation Statement and issue to
the Generator , together with copies of the relevant
meter register comparison reports (Note 2)
Generator DNO
Distribution Code 1 May 2010
Section:METER ADVANCE RECONCILIATION (GENERATION)
Subject: Interface and Timetable Information – Reconciliation of Meter Readings with Accumulated Settlement Values
REF WHEN ACTION FROM/B
Y
TO METHOD
7a Within 14
Business Days of
receipt of Meter
Reconciliation
Statement
Review Meter Reconciliation Statement and either:
(i) advise the DNO that the Meter Reconciliation
Statement is agreed
OR
(ii) discuss areas of concern with the DNO, providing
supporting evidence as necessary
Generator DNO
7b Where revisions to the initial Meter Reconciliation
Statement are agreed, prepare a replacement Meter
Reconciliation Statement and issue to Generator
DNO Generator Fax
8a On or before 15th
Business Day
after receipt of
Meter
Reconciliation
Statement
Where the Meter Reconciliation Statement is agreed,
indicate agreement on form and sign and return to the
DNO
Generator DNO Fax
8b Where the Meter Reconciliation Statement is disputed,
indicate non-agreement on form and sign and return to
the DNO. Immediately thereafter raise a formal dispute
as per the Disputes Procedure of the PPA
Generator DNO Fax
Distribution Code 1 May 2010
Section:METER ADVANCE RECONCILIATION (GENERATION)
Subject: Interface and Timetable Information – Reconciliation of Meter Readings with Accumulated Settlement Values
Ref WHEN ACTION FROM/B
Y
TO METHOD
9 Within 14 days of
receipt of agreed
Meter
Reconciliation
Statement
Issue invoice for agreed payment adjustment Generator DNO As per PPA
10 Within 14 days of
receipt of invoice
Make payment Generator
or DNO
DNO or
Generator
BACS
Note 1: time of reading shall be taken from the radio clock or data collector associated with the meter being read
Note 2: 0.02% is the maximum error due to 1 Settlement Period in 3 months (i.e. this tolerance allows for the fact that meter readings will
not be taken precisely at the end of a Settlement Period).
This tolerance is in itself tighter than the relevant accuracy of the metering system (0.5%)
Distribution Code 1 May 2010
APPENDIX A
To: [Generator] SERIAL NO:
METER ADVANCE RECONCILIATION – NOTICE OF METER READING
Northern Ireland Electricity plc hereby notifies the undermentioned Generator that all Generation tariff meters at the undermentioned site
will be read for the purposes of meter advance reconciliation pursuant to paragraph 8.8 of the Main Code of the Northern Ireland
Distribution Code on the date and at the approximate time stated below. The person(s) attending on behalf of Northern Ireland Electricity
plc is/are indicated below.
Generator:
Site:
DNO Representative(s):
Date/Time
For DNO:
Signature: Name:
(in block capitals)
Position:
Date of Issue:
Distribution Code 1 May 2010
APPENDIX B
METER ADVANCE RECONCILIATION RECORD
SHEET: OF:
GENERATOR : READING DATE : (DD.MM.YY)
SITE NAME : READING TIME : (HH.MM)
METER ID : SERIAL NO :
FUNCTION MAIN METER REGISTER READING CHECK METER REGISTER
READING
MWh EXPORT
MWh IMPORT
MVAr EXPORT
MVAr IMPORT
DNO REPRESENTATIVE GENERATOR WITNESS
PRINT NAME
SIGNATURE
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APPENDIX C
Example printout for Meter Register Comparison
21/04/89 14.20 Page 1
Meter Register Comparison for file EXAMPLE
Meter Name RTU
Name
MV Nr Reading Factor Identification
Meter Reg. Value Energy Difference
Reading
A/B
read acquired Abs %
METER_1 RTU_A 01 1 Meter 1
20/04/89 21/04/89
03:30 0:00
1551.78 2409.45 857.67 858.43 -0.76 0.088
METER_2 RTU_A 04 1 Meter 2
19/04/89 22/04/89
08:30 17:45
554.25 1245.76
3589.65 3809.02
1651.79 2569.45
857.67 857.67 1828.54 1829.01 0.47 0.025
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APPENDIX D
METER ADVANCE RECONCILIATION STATEMENT
SITE NAME: READING DATE:
GENERATOR: SERIAL NO:
SETTLEMENT VALUE AFFECTED:
Difference Recorded
in Meter Register
Comparison Report MWh
Metering Point (as appropriate)
Generator Gross Meter
Generator Transformer Meter
Unit Transformer Meter
Station Transformer Meter
Net Settlement Value Adjustment
MWh
Associated primary transformer losses are ignored in establishing the Net Settlement
Value Adjustment
For DNO:
Signed: Name:
(in block capitals)
Position:
Date:
For Generator:
Signed: Name:
(in block capitals)
Position:
Date: AGREED/DISAGREED
(Delete as appropriate)
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Agreed Procedure No. 4
VALIDATION, ESTIMATION AND SUBSTITUTION RULES
FOR HALF-HOURLY DATA
for the electricity industry in
Northern Ireland
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AGREED PROCEDURE No. 4
VALIDATION, ESTIMATION AND SUBSTITUTION RULES FOR HALF-HOURLY
DATA
Contents
1 Introduction
2 Use of the Procedure
3 Validation of Meter Details
4 Meter ID/Serial Number
5 Meter Register and Pulse Multipliers
6 Meter Data Date and Time
7 Validation of Half hourly Metering Data
8 Meter ID
9 Meter Channel Details
10 Meter Time
11 Pulse Overflow
12 Excluded Intervals
13 Number Of Intervals
14 Cumulative/Total Consumption Comparison
15 Alarms
16 Zero Interval Tolerance
17 Data Estimation and Substitution
18 Check Meter
19 Up to Two Hour Gap in Data
20 Over Two Hour gap in Data
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1 INTRODUCTION
1.1 This Agreed Procedure (the “Procedure”) describes the rules to be followed for both
data validation and data estimation for Generators with remotely read half-hourly
Metering.
1.2 The Procedure supplements the Main Code and the Sub-Codes of the Metering Code to
which reference should be made. In the event of an inconsistency between the
provisions of the Procedure and the Main Code or a Sub-Code the provisions of the
Main Code or such Sub-Code shall prevail. The provisions of the Main Code shall
prevail over the provisions of any Sub-Code.
1.3 The Procedure is part of the Grid Code and terms and expressions defined in the Grid
Code have the same meaning in the Procedure.
1.4 This Procedure applies to half hour metered Generators only. The meter advance
reconciliation procedures for Demand Customers are covered by Retail Market
Procedure MP NI 105.
2 USE OF THE PROCEDURE
2.1 The Procedure shall be used by the DNO and staff of those Generators who are metered
on a half-hourly basis who are responsible for meter advance reconciliation readings
and processing.
3 VALIDATION OF METER DETAILS
3.1 Prior to half-hourly data being accepted and approved for settlement purposes the Meter
details are validated. This occurs for new meter installations, meter changes, meters
that have been re-programmed or for existing meters moving to half-hourly profiling.
4 METER ID/SERIAL NUMBER
4.1 The Meter serial number registered to the Metering installation is verified against the
Meter id retrieved during Polling to ensure the correct meter has been polled.
5 METER REGISTER AND PULSE MULTIPLIERS
5.1 The meter Register Reading multiplier and the Pulse Multiplier are verified to ensure
data accuracy.
6 METER DATA DATE AND TIME
6.1 The date and time held by the meter and stamped on the data collected is checked to
ensure its accuracy.
7 VALIDATION OF HALF HOURLY METERING DATA
7.1 After polling each meter the half-hourly data retrieved from the meter is validated by
the data collection level and the following checks are performed.
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8 METER ID
8.1 Each Time a meter is polled the Electronic Serial Number of that meter is compared to
the Device ID stored within the data collection level. If they do not match then no data
is retrieved and the Failure is reported by the data collection level for investigation.
9 METER CHANNEL DETAILS
9.1 Each time a meter is polled the number of channels of data expected is compared
against the number actually received. If they do not agree then no data is retrieved and
the failure is reported by the DNO Data Collection System for investigation.
10 METER TIME
10.1 Each time a meter is polled it’s time is checked to ensure it falls within two minutes of
the actual time. If the time is out by more than two minutes then the data is retrieved
and the time difference is investigated. The meter will be programmed with the correct
time.
11 PULSE OVERFLOW
11.1 Each channel status for each interval is checked for pulse Overflows. If a Pulse
Overflow is reported the data is marked for estimation and the cause is investigated and
resolved.
12 EXCLUDED INTERVALS
12.1 Each Channel status for each interval is checked for any interval data that may be
excluded. If Excluded intervals are reported then those intervals are marked for
estimation and the cause is investigated.
13 NUMBER OF INTERVALS
13.1 Each time a meter is polled the number of expected half-hour time intervals between
the start and stop times of the Load profile data is calculated and compared with the
actual number of time intervals found in the Load profile data file. Any difference in
the number of time intervals is investigated and resolved.
14 CUMULATIVE/TOTAL CONSUMPTION COMPARISON
14.1 When a meter is polled and it provides an electronic cumulative reading of the prime
register equivalent to the total consumption of the meter, then the difference between
successive cumulative readings is compared to the total of the meter period data for the
same period of time.
14.2 Specifically:
14.2.1 The sum of pulses * pulse multiplier for all the recording intervals collected is
compared to the meter advance * meter multiplier for the time interval.
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14.2.2 If the difference between these values is greater than the meter register
multiplier then a secondary check is performed.
14.2.3 If the difference between actual reading and the calculated reading is more than
2 % then the problem is investigated and resolved.
15 ALARMS
15.1 When a meter is polled and significant meter alarms are flagged in the data file e.g.
long/short intervals etc. Each alarm is investigated.
16 ZERO INTERVAL TOLERANCE
16.1 If a Customer’s half hour data profile does not normally register any zero generation on
the KW Export channel then the total number of zero half hour data intervals retrieved
for the KW channel will be counted. If it exceeds 20 intervals then the data is flagged
for investigation.
17 DATA ESTIMATION AND SUBSTITUTION
17.1 Data estimation is required in situations where meter data is incomplete, has been
irretrievably lost or cannot be obtained within the timeframes required. Data
substitution is required where the data obtained is erroneous. Data will be
estimated/substituted when required using one of the following methods in the order
specified below:
18 CHECK METER
18.1 Where a check meter is installed and functional, data requiring estimation/substitution
will be taken directly from the check meter.
19 UP TO TWO HOUR GAP IN DATA
19.1 If the gap in data is 2 hours or less point –to-point linear interpolation will be used to
estimate/substitute the data. Intervals containing a power Outage are not used as end
points for interpolation:
19.1.1 If the data gap occurs in the middle of the data, the first point is the last valid
interval before the gap and the second point is the first valid interval after the
gap.
19.1.2 If the gap occurs at the beginning of the span the last interval from the historical
data is used as the first point if the historical data is available and valid.
Otherwise the second point (the first valid interval after the section) is used as
the first point – this will cause the Load to be estimated as a flat Load.
19.1.3 If the gap occurs at the end of the span the first point (the last valid interval
before the section) is used as the second point – this will cause the Load to be
estimated as a flat Load.
20 OVER TWO HOUR GAP IN DATA
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20.1 If the gap in data is greater than 2 hours then the interval data is constructed using the
average Load shape based on the three most recent “similar” periods with valid data
(i.e. data that has not been estimated). A “similar” period means the same time period
of week and can be chosen from the previous 90 days. If the period needing estimation
is a holiday, then the “similar days” should be holidays rather than the same day of
week.
20.2 If adequate data is not available to perform this then one of the methods outlined below
will be employed in the order given.
20.2.1 Where actual meter readings are available an adjustment factor shall be
calculated and applied to the data to ensure that the total estimated consumption
is equal to the total actual consumption.
20.2.2 If only two “similar” periods are available within 90 days, the average is
calculated of these two. Similarly, if only one “similar” period is available the
data for this period is used for estimation.
20.2.3 If no “similar” periods are available in the previous 90 days, the three “like”
periods that are closest chronologically prior to the period requiring estimation
are used. A “like” period means a weekday or weekend/holiday.
20.2.4 If no “similar” periods are available and three “like” periods are not available
then the average of the two “like” periods that are closest chronologically prior
to the period requiring estimation is used.
20.2.5 If no “similar” periods are available and two “like” periods are not available
then the data for the “like” period that is closest chronologically prior to the
period requiring estimation is used.
20.2.6 If there is no historical data that can be used, the data should be estimated
manually and all assumptions documented fully.
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Glossary and Definitions
In the Distribution Code the following words and expressions shall, unless the subject matter
or the context otherwise requires or is inconsistent therewith, bear the following meanings:
Active Energy the electrical energy produced, flowing or supplied
by an electrical circuit during a time interval, being
the integral with respect to time of Active Power,
measured in units of watt-hours or standard multiples
thereof, that is:
1000 Wh = 1 kWh;
1000 kWh = 1 MWh;
1000 MWh = 1 GWh.
Active Power or MW The product of the components of alternating current
and voltage that equate to true power which is
measured in units of watts and standard multiples
thereof, for example:
1000 Watts = 1kW;
1000kW = 1MW;
1000MW = 1GW.
Aggregated Demand Site A group of Individual Demand Sites represented by
a Dispatchable Demand Customer, which together
are capable of a Demand Reduction Capability
equal to or above 4MW (and which is therefore
subject to Central Dispatch from the TSO). Each
Individual Demand Site comprising an Aggregated
Demand Site shall be in one currency zone. Unless
otherwise specified, information submitted in respect
of an Aggregated Demand Site shall always be at an
aggregated level.
Aggregated Generating Unit A group of Generating Units represented by a
Generator Aggregator, each of which must not have
a Registered Capacity greater than 10MW. An
Aggregated Generating Unit with a total Registered
Capacity of 4MW or more shall be subject to
Central Dispatch, but one with a total Registered
Capacity of less than 4MW may only be subject to
Central Dispatch subject to agreement with the
TSO.
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Glossary and Definitions Page 202
Aggregator Either a Generator Aggregator or a Dispatchable
Demand Customer in respect of an Aggregated
Demand Site.
Agreed Procedure Each of the agreed procedures which are specified in
paragraph 1.10 of the Main Code and set out in the
Distribution Metering Code.
Apparatus All equipment in which electrical conductors are
used, supported or of which they may form a part.
Authority The Northern Ireland Authority for Utility
Regulation.
Automatic Load Shedding A Load shedding scheme utilised by the TSO to
prevent Frequency collapse or other problems and to
restore the balance between generation output and
Demand on the Distribution System.
Automatic Load Shedding
Device
A device for initiating Load shedding automatically,
such as a Low Frequency Relay.
Black Start The procedure necessary for a recovery from a Total
Shutdown or Partial Shutdown.
Business Day Any day (other than a Saturday or a Sunday) on
which banks are open for business in Belfast but
excluding those days which the DNO may from time
to time notify Users as being days on which normal
business will not be conducted at the DNO’s
premises.
Central Dispatch The process of issuing an instruction in relation to
CDGUs, Aggregated Generating Units and/or
Interconnectors by the TSO pursuant to the Grid
Code. In particular:
All Dispatchable WFPSs shall be subject to
Central Dispatch;
All other Power Stations with a Registered
Capacity of above 10MW shall be subject to
Central Dispatch;
All other Power Stations with a Registered
Capacity of 10MW or less can agree with the
TSO to be subject to Central Dispatch.
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Glossary and Definitions Page 203
Centrally Dispatched
Generating Unit (CDGU)
A Generating Unit within a Power Station subject
to Central Dispatch.
Commissioning/Acceptance
Test
Testing of an item of User’s Equipment required
pursuant to the Connection Conditions prior to
connection or re-connection in order to determine
whether or not it is suitable for connection to the
System and the term “Commissioning/Acceptance
Testing” shall be construed accordingly.
Committed Project Planning
Data
Has the meaning set out in paragraph 8.3 of the
Planning Code.
Compensation Factors Loss adjustment factors.
Connected System Test Has the meaning set out in paragraph 1.1(b) of OC9.
Connection Agreement The bilateral agreement between the DNO and the
User, which contains the detail specific to the User’s
connection to the Distribution System.
Connection Conditions or CC The part of the Distribution Code which is identified
as the Connection Conditions.
Connection Point A point at which a User’s Plant and/or Apparatus
connects to the Distribution System.
Connection Site A site containing a Connection Point.
Control Person The term used as an alternative to “Safety Coordinator”
on the Site Responsibility Schedule
only.
Controllable WFPS A WFPS first connected to the Distribution System
on or after 1 April 2005 whose wind turbines
comprise a Registered Capacity of 5MW or more.
Data Protection Legislation The Data Protection Act 1998 implementing
Directive 95/46/EC on the protection of individuals
with regard to the Processing of Personal Data and
including all regulations and codes of practice
applicable to those persons subject to the
Distribution Metering Code in relation to matters
the subject of the Distribution Metering Code.
Demand Customer Voltage
Reduction
A 3 or 6 per cent reduction of voltage supplied to all
or any group of Demand Customers on a particular
part of the Distribution System.
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Glossary and Definitions Page 204
Demand The amount of electrical power consumed
comprising of Active and Reactive Power unless
otherwise stated.
Demand Control As defined in paragraph 1.5 in OC3.
Demand Customer A person to whom electrical Energy is provided by
means of a direct connection to the Distribution
System.
Demand Reduction Capability The reduction capability in MW Demand that can be
achieved by the Demand Side Unit.
Demand Side Unit A Demand Site or Aggregated Demand Site with a
Demand Reduction Capability of at least 4MW.
The Demand Side Unit shall be subject to Central
Dispatch.
Department The Department of Enterprise, Trade and Industry.
Detailed Planning Data Data specified in Part 2 of the Appendix to the
Planning Code.
Development A modification relating to a User’s Plant and/or
Apparatus already connected to the Distribution
System.
Disconnect The act of physically separating Users (and Demand
Customers) equipment from the Distribution
System, and the terms “Disconnection” and
“Disconnecting” shall be construed accordingly.
Dispatchable Demand
Customer
A person who operates a Demand Side Unit, with a
Demand Reduction Capability not less than 4MW.
Dispatchable WFPS A Controllable WFPS which is dispatched via an
Electronic Interface by the TSO.
Distribution Code The document named as such, prepared pursuant to
condition 27 of the Licence held by the DNO.
Distribution Code Review Panel
(Panel)
The panel whose functions are set out in paragraph 6
of the General Conditions.
Distribution Metering Code That part of the Distribution Code identified as the
Distribution Metering Code comprising the Main
Code, each Sub-Code and each Agreed Procedure.
Distribution Code 1 May 2010
Glossary and Definitions Page 205
Distribution Service Centre A location used for the control and operation of the
Distribution System.
Distribution System The electric lines within the Authorised Area, as
defined in the Licence held by the DNO, owned by
the Distribution Licensee (but not, for the avoidance
of doubt, any lines forming part of the transmission
system or any Interconnector), and any other
electric lines which the Authority may specify as
forming part of the distribution system, together with
(in each case) any Plant and Apparatus and/or
meters owned or operated by the DNO used in
connection with the distribution of electricity.
DNO or Distribution Network
Owner
Northern Ireland Electricity plc acting in its capacity
as the owner of the Distribution System.
DNO Data Collection System The data collection system (sometimes referred to as
an “instation”) operated by the DNO to supply
Settlement Values to the Market Operator (as such
term is defined in the Trading and Settlement
Code) for use in calculating payments due, inter alia,
to Generators and from Suppliers (currently
comprising a central computer together with
datalinks to and from it connecting to System Data
Collectors), or such other data collection system as
the DNO may reasonably specify to be used for such
purpose with the prior agreement of the Authority
and after consultation with all Generators and those
other Users which are, in the reasonable opinion of
the DNO, interested in any such system. For the
avoidance of doubt, the System Data Collectors, the
Generator data collectors and the accounting
software known as the contract management system
are not part of the Data Collection System.
DNO Site A site owned (or occupied pursuant to a lease,
licence or other agreement) by the DNO in which
there is a Connection Point. For the avoidance of
doubt a site owned by a User but occupied by the
DNO as aforesaid, is a DNO Site.
Earthing A way of providing a connection between conductors
and earth by an Earthing Device.
Earthing Device A means of providing a connection between a
conductor and earth being of adequate strength and
capability.
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Glossary and Definitions Page 206
Electronic Interface A system, in accordance with the requirements of the
TSO’s data system providing an electronic interface
between the TSO and a User, for issuing and
receiving instructions, including Dispatch
Instructions, as provided for in the Grid Code and
established pursuant to an agreement between the
TSO and the User.
Emergency Manual
Disconnection
Load shedding carried out at short notice or no notice
when a Regulating Margin cannot otherwise be
achieved.
Energy The electrical energy produced, flowing or supplied
by an electrical circuit during a time interval and
being the integral with respect to time of the
instantaneous power, measured in units of Watthours
or standard multiples thereof, for example:-
1000Wh = 1kWh;
1000kWh = 1MWh;
1000MWh = 1GWh.
Event An unscheduled or unplanned (although it may have
been anticipated) occurrence on a System or on the
Transmission System including, without limiting
that general description, faults, incidents and
breakdowns.
Export In respect of any User, a flow of electricity from the
Apparatus of such User to the Apparatus of
another User and the verb “export” and its respective
tenses shall be construed accordingly.
Final Connection Report Has the meaning set out in paragraph 11.5.1 of the
Connection Conditions.
Final Report Has the meaning set out in paragraph 2.2(d) in OC9.
Finish Date The date on which an Outage is to finish.
Frequency The number of alternating current cycles per second
(expressed in Hertz) at which a System is running.
Fuel Security Code The Northern Ireland Fuel Security Code designated
by the Department as a condition of Licences
granted under Article 10 of the Order.
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Glossary and Definitions Page 207
General Conditions The part of the Distribution Code which is identified
as the General Conditions.
Generating Plant A Power Station subject to Central Dispatch
Generating Unit Other than in the case of Wind Farm Power
Stations, a generator together with all Plant and
Apparatus which relate exclusively to the operation
of that generator. In the case of Wind Farm Power
Stations, a wind turbine generator within a Wind
Farm Power Station, together with all Plant and
Apparatus (including any step-up transformer)
which relates exclusively to the operation of that
wind turbine generator.
Generator A person who generates electricity under a Licence
or exemption under the Order and who is subject to
the Distribution Code either by virtue of a Licence
or exemption or pursuant to any agreement with the
DNO or otherwise.
Generator Aggregator A person who represents several Generating Units,
each of which does not have a Registered Capacity
greater than 10MW and the combined Registered
Capacity of which is equal to or greater than 4MW
in relation to those Generating Units and receiving
Dispatch Instructions in relation to those
Generating Units from the TSO under the Grid
Code. For the avoidance of doubt, a Generator
Aggregator cannot aggregate a Generating Unit
with an output equal to or above 10MW.
Generator data collector A data collector available to transmit data directly to
the relevant Generator.
Generator Metering Circuits Current and voltage transformers in a Power Station
and their associated secondary circuits which feed
Metering and which may be owned by either the
Generator or the DNO.
Generator Terminal The terminals of a Generating Unit.
Generator Transformer The main transformer for a Generating Unit through
which that power passes from the Generator
Terminals to the Distribution System.
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Glossary and Definitions Page 208
Grid Code The Grid Code prepared pursuant to the TSO’s
Licence, as from time to time revised in accordance
with the TSO’s Licence.
Grid Code Metering Code That part of the Grid Code identified as the Grid
Code Metering Code.
High Voltage or HV A voltage exceeding 650 volts.
HV Apparatus High Voltage electrical circuits forming part of a
System.
Implementing Safety Coordinator
Has the meaning set out in paragraph 6.4 in OC6.
Import In respect of any User, a flow of electricity to the
Apparatus of such User from the Apparatus of
another User and the verb “import” and its
respective tenses shall be construed accordingly.
Independent Engineer The person appointed pursuant to paragraph 11.2 of
the Main Code in the Distribution Metering Code.
Independent Generating Plant A Power Station which is not subject to Central
Dispatch and is not a Controllable WFPS.
Induction Generating Unit A Generating Unit in which some or all of the
excitation is derived from the Distribution System
rather than being separately supplied as magnetic or
electrical energy.
Interconnector Electric lines and electric Plant used for conveying
electricity from outside both of Northern Ireland and
the Republic of Ireland directly to or from a
substation or converter station in either Northern
Ireland or the Republic of Ireland.
Interested User As defined in the Metering Code.
Inter-jurisdictional Tie Line The lines, facilities and equipment that connect the
transmission system of the Republic of Ireland to the
transmission system of Northern Ireland.
Intertripping A method of tripping a circuit breaker on receipt of a
signal initiated from protection at another location.
Investigation An investigation carried out by the DNO pursuant to
OC10 in relation to User Sites.
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Glossary and Definitions Page 209
Invitee As defined in paragraph 10.1 of the Main Code.
Isolating Device A device for the purpose of rendering Plant and HV
Apparatus either Isolated or disabled so that
electrical energy cannot pass from the Apparatus
(or, in the case of Plant, from the associated
Apparatus) to the HV Apparatus.
Isolation The disconnection of HV Apparatus from the
remainder of the System in which that HV
Apparatus is situated by means either of an
Isolating Device(s) in the isolating position or
adequate physical separation or sufficient gap or the
disablement (by means of switching or dismantling)
of Plant and/or Apparatus so that electrical energy
cannot pass from the Apparatus (or, in the case of
Plant, from the associated Apparatus) to the HV
Apparatus, other than by an Isolating Device and
“Isolated” shall be construed accordingly.
Licence A licence granted under the Order.
Licence Standards The document designated as such by the Authority
on or before SEM Go-Live, as modified from time to
time in accordance with Condition 19 of the Licence
held by the DNO.
Load The Active Power or Reactive Power, as the context
requires, generated, transmitted or distributed and all
like terms shall be construed accordingly.
Distribution Code 1 May 2010
Glossary and Definitions Page 210
Local Safety Instructions Instructions relating to each DNO Site and each User
Site approved by the relevant DNO or User in
accordance with OC6.4.1, setting down the methods
of achieving the objectives of the DNO’s or the
User’s (as the case may be) Safety Rules to ensure
the safety of personnel carrying out work or testing
on Plant and/or Apparatus to 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 sufficient gap, or the
disablement (by means of switching or dismantling)
of Plant and/or Apparatus so that electrical energy
cannot pass from the Apparatus (or, in the case of
Plant, from the associated Apparatus) to the HV
Apparatus, other than by an Isolating Device or
maintaining or securing the position of an Earthing
Device.
Location The electrical location on a System.
Low Frequency Relay An electrical measuring relay intended to operate
when its characteristic quantity (Frequency) reaches
the relay settings by decrease in Frequency.
Low Voltage or LV A voltage not exceeding 250 volts.
Main Code The part of the Distribution Metering Code entitled
the “Main Code”.
Market Operator Shall have the meaning set out in the TSC.
Market Registration Code or
MRC
The code of that name drawn up by the DNO as
amended or restated from time to time.
Medium Voltage or MV A voltage exceeding 250 volts but not exceeding 650
volts.
Meter Advance Reconciliation The process for reconciliation of meter readings with
record produced in accordance with Agreed
Procedure 3 of the Distribution Metering Code
and/or the statement produced in accordance with
Agreed Procedure 3.
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Glossary and Definitions Page 211
Meter Advance Reconciliation
Record
The record produced in accordance with Agreed
Procedure 3 of the Distribution Metering Code in
the form set out in Appendix B to Agreed Procedure
3.
Meter Reconciliation Statement A statement prepared by the DNO and submitted to
each Generator.
Meter Responsible Person As defined in paragraph 5 of the Distribution
Metering Code.
Metering Means Tariff Metering.
Metering System Means a meter and any associated voltage
transformers, current transformers and secondary
circuits.
Minimum Generation The minimum MW Output which a Generating
Unit can generate continuously, registered with the
DNO.
Minister The Minister for Enterprise, Trade and Investment.
Monitoring Monitoring carried out by the DNO pursuant to
OC10.
Monitoring Notice A notice issued by the DNO to a User pursuant to
paragraph 4.3 in OC10, informing the User that the
DNO is Monitoring its User Equipment.
NI Demand The Demand on the NI System less the output of
Independent Generating Plant.
NI System Together, the Transmission System and the
Distribution System.
Operating Code or OC That part of the Distribution Code which is
identified as the Operating Code.
Operation A scheduled or planned action relating to the
operation of a System and the Transmission System
but, for the avoidance of doubt, does not include
fault locating operations undertaken by the DNO.
Distribution Code 1 May 2010
Glossary and Definitions Page 212
Operational Effect Any effect on the operation of the relevant System or
on the Transmission System which will or may
cause the Systems of the DNO or a User, as the case
may be, to operate differently from the way in which
they would or may have operated in the absence of
that effect.
Operational Procedures Management instructions and procedures, both in
support of the Safety Rules and for the local and
remote operation of Plant and/or Apparatus at or
from a Connection Site.
Order The Electricity (Northern Ireland) Order 1992.
Other Authority The Commission for Energy Regulation in the
Republic of Ireland.
Other Transmission System The transmission system operated by the Other TSO
in the Republic of Ireland.
Other Transmission System
Operator (Other TSO)
The holder of a licence granted pursuant to Section
14 of the Electricity Regulation Act 1999 in the
Republic of Ireland to operate a Transmission
System.
Outage In relation to a Generating Unit, a total or partial
reduction in Output in connection with the repair or
maintenance of the Generating Unit or any
associated Power Station Equipment, or resulting
from a breakdown or failure of the Generating Unit
or any associated Power Station Equipment. In
relation to a Demand Customer’s Connection Site,
a total or partial reduction in Demand in connection
with the repair or maintenance of the Demand
Customer’s Connection Site or any associated
equipment or resulting from a breakdown or failure
of the Demand Customer’s Connection Site or any
associated equipment. In relation to the DNO, the
removal from service for repair, maintenance, safety
or other reason any part of the Distribution System.
Output The actual Active Power output in MW of a
Generating Unit as at the Connection Point derived
from data measured pursuant to the Metering Code.
Overall Accuracy The accuracy of any Metering as affected by its
current and voltage transformers and Generator
Metering Circuits.
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Ownership Diagram A diagram created pursuant to paragraph 9.1.4 in the
Connection Conditions and prepared following the
principles set out in Appendix 2 to the Connection
Conditions.
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 across any
Interconnector or Inter-jurisdictional Tie Line 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 the TSO’s directions relating
to a Black Start.
Personal Data The personal data (as defined in the Data Protection
Act 1998) that is collected or processed under the
Distribution Metering Code.
Planned Manual Disconnection Load shedding carried out when it is known in
advance that a Regulating Margin cannot otherwise
be achieved.
Planning Code or PC That part of the Distribution Code which is
identified as the Planning Code.
Plant Fixed and movable items other than Apparatus.
Power Station An installation comprising one or more Generating
Units (even where sited separately) owned and/or
controlled by the same Generator, which may
reasonably be considered as being managed as one
Power Station or, as the case may be, one Wind
Farm Power Station.
Power Station Equipment Items of Plant in a Power Station which are integral
to the operation of a CDGU, Controllable WFPS
and/or Dispatchable WFPS but which are not used
exclusively in the operation of such CDGU,
Controllable WFPS and/or Dispatchable WFPS,
the Outage of which will, or is likely to (when, for
example, taken together with other Power Station
Equipment Outages), reduce the level of
Availability of a CDGU, Controllable WFPS and/or
Dispatchable WFPS.
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Pre-energisation Connection
Report
Has the meanings set out in paragraphs 11.3.2 and
11.6.1 in the Connection Conditions.
Preliminary Notice Has the meaning ascribed to it in paragraph 1.2 in
the Appendix to OC9.
Preliminary Project Planning
Data
Has the meaning set out in paragraph 8.2 in the
Planning Code.
Process/Processing Has the meaning given to “process” and “processing”
under the Data Protection Act 1998.
Proposal Notice Has the meaning ascribed to it in paragraph 4.1 of
OC9.
Protected Demand Customer A Demand Customer in relation to whom, in
accordance with guidelines issued by the
Department, Planned Manual Disconnection shall,
so far as possible, not be exercised.
Protection Equipment for detecting abnormal conditions on a
System and initiating fault clearance and activating
alarms and indications.
Prudent Operating Practice In relation to a User or the TSO, the standard of
practice attained by exercising that degree of skill,
diligence, prudence and foresight which could
reasonably be expected from a skilled and
experienced operator engaged in the same type of
undertaking under the same or similar circumstances.
Reactive Energy The integral with respect to time of the Reactive
Power measured in units of volt-ampere-hours
reactive or standard multiples thereof, that is:
1000 VArh = 1 kVArh;
1000 kVArh = 1 MVArh.
Reactive Power or MVAr The product of voltage and current and the sine of
the phase angle between them measured in units of
volt-amperes reactive and standard multiples thereof,
i.e.:
1000 VAr = 1 kVAr
1000 kVAr = 1 MVAr
Record of Inter-System Safety
Precautions or RISSP
The procedures set out in paragraph 7 of OC6.
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Registered Capacity The normal full Load capacity of a Generating Unit
in MW measured as at the Connection Point and in
relation to a Wind Farm Power Station, the normal
full Load capacity of the collection of one or more
wind turbines, each being a Generating Unit, in
MW measured as at the Connection Point of the
Wind Farm Power Station.
Registered Project Planning
Data
Has the meaning set out in paragraph 8.4 of the
Planning Code.
Regulating Margin The margin of generating capacity that is
Synchronised over Demand which is required in
order to maintain Frequency control.
Relevant Connection Site a site which includes a Connection Point of a Power
Station or Demand Customer to the Distribution
System.
Requesting Safety Co-ordinator Has the meaning set out in paragraph 6.4 of OC6.
Responsible Engineer/Operator A person nominated by a User to be responsible for
control of the User’s System.
Responsible Manager A manager who has been duly authorised by a User
or the TSO to sign Site Responsibility Schedules on
behalf of that User or the TSO, as the case may be.
Re-Synchronisation The act of achieving the state where the Frequencies
and phase relationships of parts of the Total System
are identical.
Retail Market Procedure (MP) Each of the retail market procedures forming part of
the Market Registration Code.
RISSP-A and RISSP-B Have the meanings set out in paragraph 7.2 of OC6.
Rota Load Shedding Planned Disconnection of Demand Customers on a
rota basis during circumstances when there is a
significant shortfall of generation required to meet
the total Demand for a protracted period.
Safety Co-ordinator Has the meaning set out in paragraph 6 of OC6.
Safety From The System That condition which safeguards persons working or
testing HV Apparatus from the dangers which are
inherent in working on items of HV Apparatus.
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Safety Precautions Has the meaning set out in paragraph 8.1 of OC6.
Safety Rules The rules and procedures (as amended or restated
from time to time) of the DNO or a User to ensure
Safety From The System.
Schedule Day The period from 0000 hours until 2400 hours on the
same day.
Secretary of State The Secretary of State for the Department of Energy
and Climate Change
Settlement Period Has the meaning given to that term in the TSC.
Settlement Values Values of Active Energy and Reactive Energy
delivered over a Settlement Period as recorded by
Metering required by and operating in accordance
with this Distribution Metering Code or as
estimated or substituted in accordance with this
Distribution Metering Code. Settlement Values are
identified by the time at the end of the relevant
Settlement Period.
Significant Incident Has the meaning set out in paragraph 4.3.3 of OC4.
Single Electricity Market
(SEM)
The wholesale all-island single electricity market
established and governed pursuant to the relevant
legislation and the TSC.
Site A User Site or a DNO Site, as the case may be.
Site Responsibility Schedule A schedule prepared by the DNO and a User and
signed by both parties detailing the division of
responsibilities at Connection Sites towards the
ownership, control, operation and maintenance of
Plant and Apparatus and the safety of personnel at
the Connection Site. The format, principles and
basic procedure to be used in the preparation of Site
Responsibility Schedules are set down in Appendix
1 to the Connection Conditions.
Standard Planning Data Data specified in Appendix A in the Planning Code.
Start Date The date on which an Outage is to begin.
Statement on Distribution
System Capacity
The statement of that name prepared pursuant to
condition 32 of the Licence held by the DNO.
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Substation An assemblage of equipment including any necessary
housing for the conversion, transformation or control
of electrical power.
Sub-Code Each of the Sub-Codes referred to in the Main Code
and set out in the Distribution Metering Code.
Supplier The holder of a Licence to supply electricity
pursuant to Article 10(1)(c) of the Order.
Synchronised The condition where an incoming Generating Unit
or System is connected to another System so that the
Frequencies and phase relationships of that
Generating Unit or System, as the case may be, and
the System to which it is connected are identical and
all like terms shall be construed accordingly.
Synchronous Generating Unit A Generating Unit which is connected and
Synchronised to the Distribution System.
System Any User System and/or the Distribution System as
the case may be.
System Data Collector A data collector (sometimes referred to as an
“outstation”) owned by the DNO for transmitting
data to the DNO Data Collection System for the
purpose of providing Settlement Values.
System Test Has the meaning set out in paragraph 1.1 of OC9.
Tariff Metering Meters, associated current and voltage transformers,
metering protection equipment including alarms,
electrical circuitry, their associated data collectors
(including Generator data collectors) and wiring and
other devices or any part thereof which are part of
the Active Energy or Reactive Energy measuring
equipment at or relating to a Relevant Connection
Site.
Test Co-ordinator Has the meaning set out in paragraph 1.1 in the
Appendix to OC9.
Test Panel A panel, whose composition is detailed in the
Appendix to OC10, which is responsible for various
matters including considering a proposed System
Test and preparing a Test Programme.
Test Programme Has the meaning set out in paragraph 4.4 of OC9.
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Test Proposer Has the meaning set out in paragraph 4.1.4 of OC9.
Testing Testing carried out by the DNO pursuant to OC10 of
Users’ Equipment and the term “Test” shall be
construed accordingly.
Thermal Plant A Generating Unit that uses any source of thermal
Energy.
Total Shutdown The situation existing when all generation has ceased
and there is no electricity supply across any
Interconnector 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 the
TSO’s directions relating to a Black Start.
Total System Together, the NI System and all User Systems in
Northern Ireland.
Trading and Settlement Code
or TSC
The Single Electricity Market Trading and
Settlement Code adopted by the Market Operator
and approved by the by the Authority and the Other
Authority.
Transmission Interface
Agreement
The agreement of the same name entered into by the
Transmission Owner and the TSO.
Transmission Owner Northern Ireland Electricity plc in its capacity as the
owner of the Transmission System.
Transmission System The System consisting (wholly or mainly) of high
voltage electric lines and cables operated by the TSO
for the purposes of transmission of electricity from
one Power Station to a Substation or to another
Power Station or between sub-stations or to or from
any Interconnector including any Plant and
Apparatus and meters owned or operated by the
TSO or Transmission Owner in connection with the
transmission of electricity.
TSO (Transmission System
Operator)
The holder of the Licence granted pursuant to Article
10(1)(b) of the Order to operate a Transmission
System.
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TSO Data Collection System The data collection system (sometimes referred to as
an “instation”) operated by the TSO to supply
Settlement Values to the Market Operator (as such
term is defined in the Trading and Settlement
Code) for use in calculating payments due, inter alia,
to Generators and from Suppliers (currently
comprising a central computer together with
datalinks to and from it connecting to System Data
Collectors), or such other data collection system as
the TSO may reasonably specify to be used for such
purpose with the prior agreement of the Authority
and after consultation with all Generators and those
other Users which are, in the reasonable opinion of
the TSO, interested in any such system. For the
avoidance of doubt, the System Data Collectors, the
Generator data collectors and the accounting
software known as the contract management system
are not part of the Data Collection System.
TSO Licence The licence to carry out electricity transmission
activities granted pursuant to Article 10(1)(b) of the
Order.
User A term utilised in each section of the Distribution
Code specifying the persons (other than the DNO)
bound by that section. In the General Conditions the
term means all Users referred to in the individual
sections of the Distribution Code.
User Site A site owned (or occupied pursuant to a Lease,
licence or other agreement) by a User (which in the
case of an Aggregator, means the combination of the
individual Aggregated Generating Unit or
Aggregated Demand Side Unit sites as the case may
be) in which there is a Connection Point. For the
avoidance of doubt, a site owned by DNO but
occupied by a User as aforesaid, is a User Site.
User System Any system owned or operated by a User comprising
Generating Units together with Plant and/or
Apparatus connecting Generating Units and/or
Large Demand Customers’ equipment to the
Distribution System.
User’s Equipment The Plant and/or Apparatus owned and/or operated
by a User.
VAr A single unit of Reactive Power.
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Voltage Control The retention of the voltage on the System within
acceptable limits.
Wind Farm Power Station or
WFPS
A collection of one or more wind turbines owned
and/or operated by the same Generator and joined
together by a System with a single Connection
Point.
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GD2. CONSTRUCTION OF REFERENCES
In the Distribution Code:
(i) the table of contents is inserted for convenience only and shall be ignored in construing
the Distribution Code;
(ii) unless the context otherwise requires, all references to a particular paragraph,
subparagraph, Appendix or Schedule shall be a reference to that paragraph, subparagraph
Appendix or Schedule in or to that part of the Distribution 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 Order in Council or an Act of Parliament or any section
of or schedule to, or other provision of an Order in Council or 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 or deriving from the relevant Order in Council or
Act of Parliament;
(vi) references to “in writing” or “written” include typewriting, printing, lithography and
other modes of reproducing words in a legible and non-transitory form;
(vii) where the Glossary and Definitions refers to any word or term which is more
particularly defined in a part of the Distribution Code, the definition of that part of the
Distribution Code will prevail over the definition in the Glossary & Definitions in the
event of any inconsistency;
(viii) a cross-reference to another document or part of the Distribution 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;
(ix) nothing in the Distribution Code is intended to or shall derogate from the DNO’s
statutory or licence obligations;
(x) 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;
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(xi) 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
(xii) references to time are to Belfast time.