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Wind NI | Grid Code 2010

News Section

Grid Code 2010

Posted on: February 21st, 2012

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);

Distribution Code 1 May 2010

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

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

General Conditions Page 4

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,

Distribution Code 1 May 2010

General Conditions Page 5

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:-

Distribution Code 1 May 2010

General Conditions Page 6

(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.

Distribution Code 1 May 2010

General Conditions Page 7

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

Distribution Code 1 May 2010

General Conditions Page 8

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.

Distribution Code 1 May 2010

Planning Code Page 9

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.

Distribution Code 1 May 2010

Planning Code Page 10

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

Distribution Code 1 May 2010

Planning Code Page 11

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

Distribution Code 1 May 2010

Planning Code Page 12

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.

Distribution Code 1 May 2010

Planning Code Page 13

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

Distribution Code 1 May 2010

Planning Code Page 14

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

Distribution Code 1 May 2010

Connection Conditions Page 32

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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Connection Conditions Page 34

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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Connection Conditions Page 37

(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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Connection Conditions Page 39

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

Distribution Code 1 May 2010

Connection Conditions Page 46

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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Connection Conditions Page 47

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

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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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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.

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

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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(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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OC6 – Safety Co-ordination Page 81

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)

Distribution Code 1 May 2010

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)

Distribution Code 1 May 2010

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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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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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.

Distribution Code 1 May 2010

The Distribution Metering Code Page 160

(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

Distribution Code 1 May 2010

The Distribution Metering Code Page 161

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

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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.

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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.

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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.

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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

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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.

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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

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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

Distribution Code 1 May 2010

Distribution Metering Code Page 193

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

Distribution Code 1 May 2010

Distribution Metering Code Page 194

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)

Distribution Code 1 May 2010

Distribution Metering Code Page 195

Agreed Procedure No. 4

VALIDATION, ESTIMATION AND SUBSTITUTION RULES

FOR HALF-HOURLY DATA

for the electricity industry in

Northern Ireland

Distribution Code 1 May 2010

Distribution Metering Code Page 196

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

Distribution Code 1 May 2010

Distribution Metering Code Page 197

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.

Distribution Code 1 May 2010

Distribution Metering Code Page 198

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.

Distribution Code 1 May 2010

Distribution Metering Code Page 199

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

Distribution Code 1 May 2010

Distribution Metering Code Page 200

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.

Distribution Code 1 May 2010

Glossary and Definitions Page 201

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.

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

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.

Distribution Code 1 May 2010

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.

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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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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.

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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.